Edgar Filing: CHENIERE ENERGY INC

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2010


o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 001-16383

CHENIERE ENERGY, INC.

(Exact name of registrant as specified in its charter)


Delaware	95-4352386
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

700 Milam Street, Suite 800
Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

Registrant’s telephone number, including area code: (713) 375-5000

Securities registered pursuant to Section 12(b) of the Act:


Common Stock, $ 0.003 par value	NYSE Amex Equities
(Title of Class)	(Name of each exchange on which registered)

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes o No x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Exchange Act. Yes o No x

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer o	Accelerated filer x	Non-accelerated filer o	Smaller reporting company o
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No x

The aggregate market value of the registrant’s Common Stock held by non-affiliates of the registrant was approximately $163,000,000 as of June 30, 2010.

69,763,769 shares of the registrant’s Common Stock were outstanding as of February 21, 2011.

Documents incorporated by reference: The definitive proxy statement for the registrant’s Annual Meeting of Stockholders (to be filed within 120 days of the close of the registrant’s fiscal year) is incorporated by reference into Part III.

CHENIERE ENERGY, INC.

Index to Form 10-K



PART I	1
Items 1. and 2. Business and Properties	1
General	1
Our Business Strategy	2
Market Factors	2
Corporate Structure	2
Business Segments	3
LNG Terminal Business	3
Natural Gas Pipeline Business	7
LNG and Natural Gas Marketing Business	10
Subsidiaries	12
Employees and Labor Relations	12
Available Information	12
Item 1A. Risk Factors	13
Risks Relating to Our Financial Matters	13
Risks Relating to Our LNG Terminal Business	17
Risks Relating to Our Natural Gas Pipeline Business	20
Risks Relating to Our LNG and Natural Gas Marketing Business	22
Risks Relating to Our LNG Business in General	23
Risks Relating to Our Business in General	26
Item 1B. Unresolved Staff Comments	28
Item 3. Legal Proceedings	28
Item 4. (Removed and Reserved)	28
PART II	29
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	29
Item 6. Selected Financial Data	30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation	32
Introduction	32
Overview of Business	32
Overview of Significant 2010 Events	32
Liquidity and Capital Resources	33
Contractual Obligations	44
Results of Operations	44
Off-Balance Sheet Arrangements	48
Inflation and Changing Prices	48
Summary of Critical Accounting Policies and Estimates	49
Recent Accounting Standards	52
Item 7A. Quantitative and Qualitative Disclosures about Market Risk	52
Item 8. Financial Statements and Supplementary Data	53
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	88
Item 9A. Controls and Procedures	88
Item 9B. Other Information	88
PART III	88
PART IV	88
Item 15. Exhibits and Financial Statement Schedules	88

CAUTIONARY STATEMENT

REGARDING FORWARD-LOOKING STATEMENTS

This annual report contains certain statements that are, or may be deemed to be, “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical facts, included herein or incorporated herein by reference are “forward-looking statements.” Included among “forward-looking statements” are, among other things:

•

statements relating to the construction or operation of each of our proposed liquefied natural gas (“LNG”) terminals or our proposed pipelines or liquefaction facilities, or expansions or extensions thereof, including statements concerning the completion or expansion thereof by certain dates or at all, the costs related thereto and certain characteristics, including amounts of regasification, transportation, liquefaction and storage capacity, the number of storage tanks, LNG trains, docks, pipeline deliverability and the number of pipeline interconnections, if any;


•	statements that we expect to receive an order from the Federal Energy Regulatory Commission (“FERC”) authorizing us to construct and operate proposed LNG receiving terminals, liquefaction facilities or proposed pipelines by certain dates, or at all;


•	statements regarding future levels of domestic natural gas production, supply or consumption; future levels of LNG imports into North America; sales of natural gas in North America or other markets; exports of LNG from North America; and the transportation, other infrastructure or prices related to natural gas, LNG or other energy sources or hydrocarbon products;


•	statements regarding any financing or refinancing transactions or arrangements, or ability to enter into such transactions or arrangements, whether on the part of Cheniere or any subsidiary or at the project level;

•

statements regarding any commercial arrangements presently contracted, optioned or marketed, or potential arrangements, to be performed substantially in the future, including any cash distributions and revenues anticipated to be received and the anticipated timing thereof, and statements regarding the amounts of total LNG regasification, liquefaction or storage capacity that are, or may become, subject to such commercial arrangements;


•	statements regarding counterparties to our commercial contracts, memoranda of understanding ("MOUs"), construction contracts and other contracts;


•	statements that we expect to receive an order from the U.S. Department of Energy ("DOE") authorizing us to export domestically produced natural gas as LNG to certain countries, or at all;


•	statements regarding any business strategy, any business plans or any other plans, forecasts, projections or objectives, including potential revenues and capital expenditures, any or all of which are subject to change;


•	statements regarding legislative, governmental, regulatory, administrative or other public body actions, requirements, permits, investigations, proceedings or decisions;


•	statements regarding our anticipated LNG and natural gas marketing activities; and


•	any other statements that relate to non-historical or future information.

These forward-looking statements are often identified by the use of terms and phrases such as “achieve,” “anticipate,” “believe,” “contemplate,” “develop,” “estimate,” “expect,” “forecast,” “plan,” “potential,” “project,” “propose,” “strategy” and similar terms and phrases, or by the use of future tense. Although we believe that the expectations reflected in these forward-looking statements are reasonable, they do involve assumptions, risks and uncertainties, and these expectations may prove to be incorrect. You should not place undue reliance on these forward-looking statements, which are made as of the date of and speak only as of the date of this annual report.

Our actual results could differ materially from those anticipated in these forward-looking statements as a result of a variety of factors, including those discussed in “Risk Factors.” All forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these risk factors.

DEFINITIONS

In this annual report, unless the context otherwise requires:


•	Bcf means billion cubic feet;


•	Bcf/d means billion cubic feet per day;


•	EPC means engineering, procurement and construction;


•	EPCM means engineering, procurement, construction and management;


•	LNG means liquefied natural gas;


•	LNG Train means an independent modular unit for gas liquefaction;


•	MMBtu means million British thermal units;


•	MMcf/d means million cubic feet per day;


•	Mtpa means million metric tons per annum; and


•	TUA means terminal use agreement.

PART I

ITEMS 1. AND 2. BUSINESS AND PROPERTIES

General

Cheniere Energy, Inc. (NYSE Amex Equities: LNG), a Delaware corporation, is a Houston-based energy company primarily engaged in LNG-related businesses. We own and operate the Sabine Pass LNG terminal in Louisiana through our 90.6% ownership interest in and management agreements with Cheniere Energy Partners, L.P. (“Cheniere Partners”) (NYSE Amex Equities: CQP), which is a publicly traded partnership we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with natural gas markets in North America. One of our subsidiaries, Cheniere Marketing, LLC (“Cheniere Marketing”), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, and is working to monetize LNG storage and regasification capacity reserved by Cheniere Partners at the Sabine Pass LNG terminal. Cheniere Partners is developing a liquefaction project to provide bi-directional LNG import and export service at the Sabine Pass LNG terminal. We are in various stages of developing other LNG terminal and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision. Unless the context requires otherwise, references to the “Company”, “Cheniere”, “we”, “us” and “our” refer to Cheniere Energy, Inc. and its subsidiaries, including our publicly traded subsidiary partnership, Cheniere Partners.

LNG is natural gas that, through a refrigeration process, has been reduced to a liquid state, which represents approximately 1/600th of its gaseous volume. The liquefaction of natural gas into LNG allows it to be shipped economically from areas of the world where natural gas is abundant and inexpensive to produce to other areas where natural gas demand and infrastructure exist to justify economically the use of LNG. LNG is transported using oceangoing LNG vessels specifically constructed for this purpose. LNG liquefaction terminals compress and refrigerate natural gas into a liquid state and deliver the resulting LNG onto LNG vessels that transport the LNG to LNG receiving terminals. LNG receiving terminals offload LNG from LNG vessels, store the LNG prior to processing, heat the LNG to return it to a gaseous state and deliver the resulting natural gas into pipelines for transportation to market.

Our Business Strategy

In addition to safely maintaining the operations of the Sabine Pass LNG terminal and the Creole Trail Pipeline, our primary business strategies are to:


•	monetize the 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal held by one of Cheniere Partners' subsidiaries, Cheniere Energy Investments, LLC ("Cheniere Investments"), and monetize the 2.0 Bcf/d of natural gas transportation capacity on the Creole Trail Pipeline by:


◦	entering into long-term commercial agreements for regasification or bi-directional service;


◦	expanding operations to include bi-directional service capabilities;


◦	developing a portfolio of long-term, short-term and spot LNG purchase and sale agreements; and


◦	entering into business relationships for the marketing of natural gas that is processed at the Sabine Pass LNG terminal; and


•	restructure our finances and optimize our capital structure.

In addition, our long-term strategy is to develop and construct additional LNG terminals and natural gas pipelines and related infrastructure when market and financial conditions are favorable.

Market Factors

Our ability to successfully execute our business strategies will be impacted by many factors, including: changes in worldwide supply and demand for natural gas and LNG; the relative prices for natural gas in North America and international markets; the willingness of LNG producers and international LNG buyers to invest new capital and secure access to North American natural gas markets on a long-term basis; and access capital to market natural gas and LNG and to develop and construct liquefaction or other future LNG terminals, pipeline and other infrastructure projects.

We expect global demand for natural gas to grow significantly as more nations are seeking environmentally cleaner and more abundant and reliable fuel alternatives to oil and coal. In addition, global buyers of natural gas will need to source additional energy supplies to meet future economic growth and balance their energy portfolios. Most of the rapidly growing natural gas markets are in developing countries in Asia, particularly India and China, the Middle East and South America.

In recent years, North American domestic natural gas production has been on an upward trend, due in part to rapid growth in unconventional natural gas basins coupled with technological advances in horizontal drilling. As a result, natural gas reserves and production capacity in North America have increased significantly, exceeding expected North American natural gas demand as a result of a variety of factors, including improved energy efficiency and shifting economic activities to less energy-dependent activities.

In response to the shifting global and domestic natural gas market fundamentals, which have reduced demand for LNG regasification services in North America, we are developing the Cheniere Partners liquefaction project to expand our operations at the Sabine Pass LNG terminal and Creole Trail Pipeline to provide bi-directional import and export service to new customers. We believe that the bi-directional service would offer customers an attractively priced option to access the North American market for natural gas supply or natural gas demand, as global fundamentals dictate. The new service would utilize the LNG storage capacity, ship berthing rights, regasification capacity, and pipeline transport capacity that we hold at the Sabine Pass LNG terminal and on the Creole Trail Pipeline through our subsidiaries.

Corporate Structure

As of December 31, 2010, we held approximately 90.6% of Cheniere Partners, including 100% of its general partner. Although results are consolidated for financial reporting, we and Cheniere Partners operate with independent capital structures. Cash flow available to us from Cheniere Partners is primarily in the form of management fees and cash distributions declared and paid to us on our common units and general partner interest. See "Management's Discussion and Analysis of Financial Condition and Results of Operations" for more discussion on how we receive cash flow from Cheniere Partners.

The following diagram depicts our abbreviated capital structure, including our ownership of Cheniere Partners and Sabine Pass LNG, L.P. (“Sabine Pass LNG”) as of December 31, 2010.

Business Segments

Our business activities are conducted by three operating segments for which we provide information in our consolidated financial statements for the years ended December 31, 2010, 2009 and 2008. These three segments are our:


•	LNG terminal business;


•	natural gas pipeline business; and


•	LNG and natural gas marketing business.

For information about our segments’ revenues, profits and losses and total assets, see Note 21—“Business Segment Information” of our Notes to Consolidated Financial Statements.

LNG Terminal Business

We began developing our LNG terminal business in 1999 and were among the first companies to secure sites and commence development of new LNG terminals in North America. We focused our development efforts on three LNG terminal projects: Sabine Pass LNG in western Cameron Parish, Louisiana on the Sabine Pass Channel; Corpus Christi LNG near Corpus Christi, Texas; and Creole Trail LNG at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. We constructed the Sabine Pass LNG terminal, which is owned through Cheniere Partners, in which we hold an approximate 90.6% interest. We currently own 100% interests in both the Corpus Christi and Creole Trail LNG terminal projects.

Sabine Pass LNG Terminal

We have constructed and are operating the Sabine Pass LNG terminal in western Cameron Parish, Louisiana, on the Sabine Pass Channel. In 2003, we formed Sabine Pass LNG to own, develop and operate the Sabine Pass LNG terminal. We have long-term leases for three tracts of land consisting of 853 acres in Cameron Parish, Louisiana. The Sabine Pass LNG terminal has a regasification capacity of approximately 4.0 Bcf/d (with peak capacity of approximately 4.3 Bcf/d) and aggregate LNG storage capacity of approximately 16.9 Bcf.

Customers

Approximately 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal has been reserved under two long-term third-party TUAs, under which Sabine Pass LNG’s customers are required to pay fixed monthly fees, whether or not they use the LNG terminal. Capacity reservation fee TUA payments are made by our third-party TUA customers as follows:


•	Total Gas and Power North America, Inc. (“Total”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and


•	Chevron U.S.A., Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

The remaining approximately 2.0 Bcf/d of regasification capacity has been reserved by Cheniere Partners through a TUA between Cheniere Investments and Sabine Pass LNG. Cheniere Investments is required to make approximately $250 million per year of capacity payments to Sabine Pass LNG through at least September 30, 2028; however, the revenue earned by Sabine Pass LNG and the capacity payments under the TUA are eliminated upon consolidation of our financial statements. See "—LNG and Natural Gas Marketing Business" below for a discussion of the Variable Capacity Rights Agreement ("VCRA") between Cheniere Investments and Cheniere Marketing entered into in order to monetize Cheniere Investments' 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal.

Liquefaction Project

In June 2010, Cheniere Partners initiated a project to add liquefaction services at the Sabine Pass LNG terminal that would transform the terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG. As currently contemplated, the liquefaction project would be designed and permitted for up to four LNG Trains, each with a nominal production capacity of approximately 4.0 mtpa. We anticipate LNG export from the Sabine Pass LNG terminal could commence as early as 2015, and may be constructed in phases, with each LNG Train commencing operations approximately six to nine months after the previous LNG Train.

We intend for Sabine Pass Liquefaction, LLC ("Sabine Liquefaction"), a wholly owned subsidiary of Cheniere Partners, to enter into long-term, fixed-fee contracts for at least 3.5 mtpa (approximately 0.5 Bcf/d) of bi-directional LNG processing capacity per LNG Train, for a fee between $1.40 and $1.75 per MMBtu, before reaching a final investment decision regarding the development of the LNG Trains. As of February 25, 2011, Sabine Liquefaction had entered into eight non-binding memoranda of understanding (“MOU”) with potential customers for the proposed bi-directional facility representing a total of up to 9.8 mtpa of capacity. Each MOU is subject to negotiation and execution of definitive agreements and certain other customary conditions and does not represent a final and binding agreement with respect to its subject matter. We are negotiating definitive agreements with these and other potential customers.

In August 2010, Sabine Liquefaction received approval from the FERC to begin the pre-filing process required to seek authorization to commence construction of the liquefaction project. In January 2011, the pre-filing period was completed and therefore Sabine Liquefaction submitted an application to the FERC requesting authorization to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal. In September 2010, the DOE granted Sabine Liquefaction an order authorizing Sabine Liquefaction to export up to 16 mtpa (approximately 800 Bcf per year) of domestically produced LNG from the Sabine Pass LNG terminal to Free Trade Agreement ("FTA") countries for a 30-year term, beginning on the earlier of the date of first export or September 7, 2020. In September 2010, Sabine Liquefaction filed a second application requesting expansion of the order to include countries with which the U.S. does not have an FTA.

Sabine Liquefaction has engaged Bechtel to complete front-end engineering and design work and to negotiate a lump-sum, turnkey contract based on an open book cost estimate. We currently estimate that total construction costs will be consistent with other recent liquefaction expansion projects constructed by Bechtel, or approximately $400 per metric ton, before financing costs. We have additional work to complete with Bechtel to be able to make an estimate specific to our site and project. Our cost estimates are subject to change due to factors such as changes in design, increased component and material costs, escalation of labor costs, cost overruns and increased spending to maintain a construction schedule.

In December 2010, Sabine Liquefaction engaged SG Americas Securities, LLC, the U.S. broker-dealer subsidiary of Societe Generale Corporate & Investment Banking (SG CIB) for general financial strategy and planning in connection with the development and financing of liquefaction facilities at the Sabine Pass LNG terminal.

Cheniere Partners will contemplate making a final investment decision to commence construction of the liquefaction project upon, among other things, entering into acceptable commercial arrangements, receiving regulatory authorization to construct and operate the liquefaction assets and obtaining adequate financing.

Corpus Christi LNG Terminal

We formed Corpus Christi LNG, L.P. (“Corpus Christi LNG”) in May 2003 to develop the Corpus Christi LNG terminal near Corpus Christi, Texas. The Corpus Christi LNG terminal, if constructed, would be located on 612 acres and was designed, and permitted by the FERC, with a regasification capacity of approximately 2.6 Bcf/d, three LNG storage tanks with an aggregate LNG storage capacity of approximately 10.1 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In December 2005, the FERC issued an order authorizing Corpus Christi LNG to commence initial construction for LNG regasification services at the Corpus Christi LNG terminal, subject to satisfaction of certain conditions specified by the FERC. Preliminary site work has been completed. We will contemplate making a final investment decision to construct the Corpus Christi LNG terminal upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements.

Creole Trail LNG Terminal

We formed Creole Trail LNG, L.P. (“Creole Trail LNG”) in December 2004 to develop the Creole Trail LNG terminal at the mouth of the Calcasieu Channel in central Cameron Parish, Louisiana. We have options to lease tracts of land comprising 1,750 acres in Cameron Parish, Louisiana for the project site. The Creole Trail LNG terminal was designed, and permitted by the FERC, with a regasification capacity of approximately 3.3 Bcf/d, four LNG storage tanks with an aggregate LNG storage capacity of approximately 13.5 Bcf and two unloading docks capable of handling the largest LNG carriers currently being operated or built. In June 2006, the FERC authorized Creole Trail LNG to site, construct and operate regasification services at the Creole Trail LNG terminal. We will contemplate making a final investment decision to commence construction of the Creole Trail LNG terminal upon, among other things, achieving acceptable commercial arrangements and entering into acceptable financing arrangements.

Other LNG Terminal Sites

We continue to evaluate, and may develop, additional sites that we believe may be commercially desirable locations for LNG terminals and other facilities.

LNG Terminal Competition

Our LNG terminal business competes with other companies that are constructing and operating LNG terminals in the U.S. and in other places around the world. According to the FERC, as of December 31, 2010, there were nine existing LNG receiving terminals in North America, two of which are offshore facilities for receiving natural gas regasified from LNG onboard specialized LNG vessels, as well as other new LNG receiving terminals or expansions approved or proposed to be constructed. To the extent that we may desire to sell regasification capacity in our LNG terminals, we will compete with other third-party LNG receiving terminals or existing terminals having uncommitted capacity. In connection with our efforts to obtain LNG to exploit Cheniere Investments' regasification capacity at the Sabine Pass LNG terminal, we must compete in the world LNG market to purchase and transport cargoes of LNG.

With the development of liquefaction facilities at the Sabine Pass LNG terminal, we will compete with existing and proposed liquefaction facilities worldwide in our attempt to enter into commercial arrangements for providing bi-directional service at the Sabine Pass LNG terminal. At least three other companies have announced plans to develop liquefaction facilities in North America.

Many of the companies with which we compete are major energy corporations with longer operating histories, more development experience, greater name recognition, greater financial, technical and marketing resources and greater access to markets than we do.

LNG Terminal Governmental Regulation

Our LNG terminal operations are subject to extensive regulation under federal, state and local statutes, rules, regulations and laws. These laws require that we engage in consultations with appropriate federal and state agencies and that we obtain and maintain applicable permits and other authorizations before commencement of construction and operation of LNG terminals. This regulatory burden increases the cost of constructing and operating the LNG terminals, and failure to comply with such laws could result in substantial penalties. Through construction, commissioning and operations, we have been in substantial compliance with all regulations discussed herein.

FERC

In order to site and construct our proposed LNG terminals, we must receive and are required to maintain authorization from the FERC under Section 3 of the Natural Gas Act of 1938 (“NGA”). We will be required to obtain and maintain authorizations from the FERC to site, construct and operate liquefaction and export facilities at the Sabine Pass LNG terminal site. In addition, orders from the FERC authorizing construction of an LNG terminal are typically subject to specified conditions that must be satisfied throughout the construction, commissioning and operation of terminals. Throughout the life of our LNG terminals, they will be subject to regular reporting requirements to the FERC and the U.S. Department of Transportation regarding the operation and maintenance of the facilities.

In 2005, the Energy Policy Act of 2005 (“EPAct”) was signed into law. The EPAct gave the FERC exclusive authority to approve or deny an application for the siting, construction, expansion or operation of an LNG terminal. The EPAct amended the NGA to prohibit market manipulation. The EPAct increased civil and criminal penalties for any violations of the NGA and Natural Gas Policy Act of 1978 (“NGPA”) and any rules, regulations or orders of the FERC issued under these acts, up to $1.0 million per day per violation. In accordance with the EPAct, the FERC issued a final rule making it unlawful for any entity, in connection with the purchase or sale of natural gas or transportation service subject to the FERC’s jurisdiction, to defraud, make an untrue statement or omit a material fact or engage in any practice, act or course of business that operates or would operate as a fraud.

Other Federal Governmental Permits, Approvals and Consultations

In addition to the FERC authorization under Section 3 of the NGA, our construction and operation of LNG terminals and the liquefaction project are also subject to additional federal permits, orders, approvals and consultations required by other federal agencies, including: DOE, Advisory Council on Historic Preservation, U.S. Army Corps of Engineers, U.S. Department of Commerce, National Marine Fisheries Services, U.S. Department of the Interior, U.S. Fish and Wildlife Service, U.S. Environmental Protection Agency (“EPA”) and U.S. Department of Homeland Security.

Our LNG terminals are also subject to U.S. Department of Transportation safety regulations and standards for the transportation and storage of LNG and regulations of the U.S. Coast Guard relating to maritime safety and facility security. Moreover, our LNG terminals are also subject to state and local laws, rules and regulations.

LNG Terminal Environmental Regulation

Our LNG terminal operations and the liquefaction project are subject to various federal, state and local laws and regulations relating to the protection of the environment. These environmental laws and regulations may impose substantial penalties for noncompliance and substantial liabilities for pollution. Many of these laws and regulations restrict or prohibit the types, quantities and concentration of substances that can be released into the environment and can lead to substantial liabilities for non-compliance or releases. Failure to comply with these laws and regulations may also result in substantial civil and criminal fines and penalties.

Clean Air Act (CAA)

Our LNG terminal operations and the liquefaction project are subject to the federal CAA and comparable state and local laws. We may be required to incur certain capital expenditures over the next several years for air pollution control equipment in connection with maintaining or obtaining permits and approvals addressing other air emission-related issues. We do not believe, however, that our operations, or the construction and operations of our liquefaction project, will be materially and adversely affected by any such requirements.

The U.S. Supreme Court has ruled that the EPA has authority under existing legislation to regulate carbon dioxide and other heat-trapping gases in mobile source emissions. Mandatory reporting requirements were promulgated by the EPA and finalized on October 30, 2009. This rule requires mandatory reporting for greenhouse gases from stationary fuel combustion sources. An additional section, which requires reporting for all fugitive emissions throughout LNG terminals, was finalized in November 2010. In addition, Congress has considered proposed legislation directed at reducing “greenhouse gas emissions.” It is not possible at this time to predict how future regulations or legislation may address greenhouse gas emissions and impact our business. However, future regulations and laws could result in increased compliance costs or additional operating restrictions, and could have a material adverse effect on our business, financial position, results of operations and cash flows.

Coastal Zone Management Act (CZMA)

Our LNG terminals and liquefaction project are subject to the requirements of the CZMA throughout the construction of facilities located within the coastal zone. The CZMA is administered by the states (in Louisiana, by the Department of Natural Resources, and in Texas, by the Railroad Commission and the General Land Office). This program is implemented in coordination with the Department of the Army construction permitting process to ensure that impacts to coastal areas are consistent with the intent of the CZMA to manage the coastal areas.

Clean Water Act (CWA)

Our LNG terminal operations are subject to the federal CWA and analogous state and local laws. Pursuant to certain requirements of the CWA, the EPA has adopted regulations concerning discharges of wastewater and storm water runoff. This program requires covered facilities to obtain individual permits, participate in a group permit or seek coverage under an EPA general permit.

Resource Conservation and Recovery Act (RCRA)

The federal RCRA and comparable state statutes govern the disposal of “hazardous wastes.” In the event any hazardous wastes are generated in connection with our LNG terminal operations, we are subject to regulatory requirements affecting the handling, transportation, treatment, storage and disposal of such wastes.

Endangered Species Act

Our LNG terminal operations and planned activities, including our liquefaction project, may be restricted by requirements under the Endangered Species Act, which seeks to ensure that human activities neither jeopardize endangered or threatened animal, fish and plant species nor destroy or modify their critical habitats.

National Historic Preservation Act (NHPA)

Construction of our proposed liquefaction facilities will be subject to requirements under Section 106 of the NHPA. The NHPA requires projects to take into account the effects of their actions on historic properties. These programs are administered by the State Historic Preservation Officers ("SHPOs"). Any areas where ground disturbance will occur are required to be reviewed by the affected SHPOs.

Natural Gas Pipeline Business

We formed Cheniere Pipeline Company, a wholly owned subsidiary, to develop natural gas pipelines to provide access to North American natural gas markets for customers of our Sabine Pass and proposed Corpus Christi and Creole Trail LNG terminals. We are also developing other pipeline projects not primarily related to our LNG terminals. Our pipeline systems developed in conjunction with our LNG terminals will interconnect with multiple interstate pipelines, providing a means of transporting natural gas between trading points in the Gulf Coast and our LNG terminals. Our other projects are market-focused, seeking to connect natural gas supplies to growing markets. Our ultimate decisions regarding further development of new pipeline projects will depend upon future events, including, in particular, customer preferences and general market demand for pipeline transportation of natural gas from or to a particular LNG terminal.

Creole Trail Pipeline

The Creole Trail Pipeline is a permitted 153-mile natural gas pipeline. We have constructed, placed in-service and are operating the first 94 miles of the Creole Trail Pipeline, connecting the Sabine Pass LNG terminal to numerous interconnection points with existing interstate and intrastate natural gas pipelines in southwest Louisiana. The remaining 59 miles of permitted natural gas pipeline, if constructed, will traverse east starting at the terminus of the first 94 miles of natural gas pipeline, with interconnections to additional existing interstate natural gas pipelines.

We will contemplate making a final investment decision to construct the remaining 59 miles of permitted natural gas pipeline upon, among other things, entering into acceptable commercial and financing arrangements.

Customers

Cheniere Marketing and other third parties have entered into interruptible transportation agreements with Creole Trail Pipeline.

Liquefaction Project

In connection with Sabine Pass Liquefaction's proposed liquefaction project, we are developing a project to add additional capabilities to the Creole Trail Pipeline to be able to provide a bi-directional pipeline transportation service. We will contemplate making a final investment decision to commence construction upon, among other things, entering into acceptable commercial and financing arrangements.

Corpus Christi Pipeline

We formed Cheniere Corpus Christi Pipeline, L.P., a wholly owned subsidiary, to develop a 24-mile, 48-inch interstate natural gas pipeline that is designed to transport 2.6 Bcf/d of natural gas, from the Corpus Christi LNG terminal northwesterly along a corridor that will allow for interconnection points with various interstate and intrastate natural gas transmission pipelines. The FERC issued an order in April 2005 authorizing us to construct, own and operate the Corpus Christi Pipeline, subject to specified conditions that must be satisfied. We will contemplate making an investment decision to commence construction of the Corpus Christi Pipeline upon, among other things, entering into acceptable commercial and financing arrangements for both the Corpus Christi Pipeline and the Corpus Christi LNG terminal.

Other Pipelines

We continue to evaluate, and may develop, additional pipelines that we believe may be commercially desirable based on customer preferences and general market demand for natural gas.

The proposed Southern Trail Pipeline project would interconnect with takeaway pipelines from LNG terminals in southwestern Louisiana and Mississippi, multiple onshore pipelines serving conventional basins along the Gulf Coast and unconventional shale plays in Texas, Louisiana and Arkansas. The Southern Trail Pipeline would supply Florida with natural gas needed to supply growth that we anticipate in natural gas-fired generation capacity in that state. This pipeline would provide natural gas suppliers with access to new markets while improving natural gas supply security for Florida and the Southeastern U.S. As currently contemplated, the Southern Trail Pipeline would involve the construction of approximately 350 miles of up to 42-inch diameter pipeline.

The Burgos Hub Project is a proposed integrated pipeline project traversing the United States and Mexico border, and a related underground natural gas storage facility in Mexico, which would provide an additional market for increasing natural gas production in South Texas.

We will contemplate making a final investment decision to commence construction of each of these natural gas pipelines upon, among other things, entering into acceptable commercial and financing arrangements and applying for and receiving authorization to construct and operate the natural gas pipelines.

Natural Gas Pipeline Competition

Our existing and proposed pipelines will compete with intrastate and interstate pipelines throughout the Gulf Coast region. The principal elements of competition among pipelines are rates, terms of service, access to supply and flexibility and reliability of service. In addition, the FERC’s continuing efforts to increase competition in the natural gas industry are increasing the natural gas transportation options of a pipeline’s traditional customers.

Our pipelines will face competition from other interstate and/or intrastate pipelines that connect with our LNG terminals. In particular, our Creole Trail Pipeline competes with the Kinder Morgan Louisiana Pipeline owned by Kinder Morgan Energy Partners, L.P. (“Kinder Morgan”). Kinder Morgan has built a 3.2 Bcf/d take-away pipeline system from the Sabine Pass LNG terminal. Total and Chevron have both signed agreements with Kinder Morgan securing 100% of the initial capacity on the Kinder Morgan Louisiana Pipeline for 20 years.

Natural Gas Pipeline Governmental Regulation

Interstate Natural Gas Pipelines

Under the NGA, the FERC is granted authority to approve, and if necessary, set “just and reasonable rates” for the transportation or sale of natural gas in interstate commerce. In addition, under the NGA, we are not permitted to unduly discriminate or grant undue preference as to our rates or the terms and conditions of service. The FERC has the authority to grant certificates allowing construction and operation of facilities used in interstate gas transportation and authorizing the provision of services. Under the NGA, the FERC’s jurisdiction generally extends to the transportation of natural gas in interstate commerce, to the sale in interstate commerce of natural gas for resale for ultimate consumption for domestic, commercial, industrial, or any other use, and to natural gas companies engaged in such transportation or sale. However, the FERC’s jurisdiction does not extend to the production, gathering, or local distribution of natural gas.

In general, the FERC’s authority to regulate interstate natural gas pipelines and the services that they provide includes:


•	rates and charges for natural gas transportation and related services;


•	the certification and construction of new facilities;


•	the extension and abandonment of services and facilities;


•	the maintenance of accounts and records;


•	the acquisition and disposition of facilities;


•	the initiation and discontinuation of services; and


•	various other matters.

Under the EPAct, failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies, including civil and criminal penalties of up to $1.0 million per day per violation.

For a number of years the FERC has implemented certain rules referred to as Standards of Conduct aimed at ensuring that an interstate natural gas pipeline not provide certain affiliated entities with preferential access to transportation service or non-public information about such service. These rules have been subject to revision by the FERC from time to time, most recently in October 2008 when the FERC issued a final rule, Order No. 717, on Standards of Conduct for Transmission Providers. Order No. 717 eliminated the concept of energy affiliates and adopted a “functional approach” that applies Standards of Conduct to individual officers and employees based on their job functions, not on the company or division in which the individual works. The general principles of the Standards of Conduct are: non-discrimination, independent functioning, no conduit and transparency. These general principles govern the relationship between marketing function employees conducting transactions with affiliated pipeline companies and transportation function employees. We have established the required policies and procedures to comply with the Standards of Conduct and are subject to audit by the FERC to review compliance, policies and our training programs.

Our pipelines that interconnect with our LNG terminals are interstate natural gas pipelines. We are required to obtain authorization from the FERC pursuant to Section 7 of the NGA to construct and operate these pipelines. The rates that we charge are subject to the FERC's regulation under Sections 4 and 5 of the NGA. Our interstate pipelines also are subject to the FERC's open access requirements and the FERC's Standards of Conduct. The FERC's exercise of jurisdiction over interstate natural gas pipelines is substantially broader than its exercise of jurisdiction over LNG terminals.

Natural Gas Pipeline Safety

Louisiana and Texas administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the NGPSA may result in the imposition of administrative, civil and criminal remedies.

The Pipeline Safety Improvement Act of 2002 (“PSIA”), which is administered by the U.S. Department of Transportation Office of Pipeline Safety, governs the areas of testing, education, training and communication. The PSIA requires pipeline companies to perform extensive integrity tests on natural gas transportation pipelines that exist in high population density areas designated as “high consequence areas.” Pipeline companies are required to perform the integrity tests on a seven-year cycle. The risk ratings are based on numerous factors, including the population density in the geographic regions served by a particular pipeline, as well as the age and condition of the pipeline and its protective coating. Testing consists of hydrostatic testing, internal electronic testing, or direct assessment of the piping. In addition to the pipeline integrity tests, pipeline companies must implement a qualification program to make certain that employees are properly trained. Pipeline operators also must develop integrity management programs for gas transportation pipelines, which requires pipeline operators to perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipeline segments that could impact a high consequence area; improve data collection, integration and analysis; repair and remediate the pipeline, as necessary; and implement preventive and mitigation actions.

In 2009, the U.S. Department of Transportation issued a final rule (known as “Control Room Management Rule”) requiring pipeline operators to institute certain control room procedures that address human factors and alarm management. Prior to start-up of the Creole Trail Pipeline, we developed written control room operating procedures consistent with the then-proposed rule. We are reviewing the manual to assure full compliance with the final rule. We are required to develop the procedures by August 1, 2011 and to implement the procedures by February 1, 2013.

Energy Policy Act of 2005

The EPAct and the FERC’s policies promulgated thereunder contain numerous provisions relevant to the natural gas industry and to interstate pipelines. See “—LNG Terminal Business—LNG Terminal Governmental Regulation” above.

Natural Gas Pipeline Environmental Regulation

Our natural gas pipeline business is subject to the same federal, state and local laws and regulations relating to the protection of the environment that are applicable to our LNG terminals. See “—LNG Terminal Business—LNG Terminal Environmental Regulation” above.

LNG and Natural Gas Marketing Business

Our wholly owned subsidiary, Cheniere Marketing, is engaged in the LNG and natural gas marketing business and is seeking to monetize the 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal held by Cheniere Investments through Cheniere Marketing's VCRA with Cheniere Investments. Cheniere Marketing is seeking to develop a portfolio of long-term, short-term, and spot LNG purchase and sale agreements; assist Cheniere Investments in negotiating with potential customers for bi-directional service at the Sabine Pass LNG terminal; and enter into business relationships for the domestic marketing of natural gas imported by Cheniere Marketing as LNG to the Sabine Pass LNG terminal.

In 2009, Cheniere Marketing began purchasing, transporting and unloading commercial LNG cargoes into the Sabine Pass LNG terminal and has used trading strategies intended to maximize margins on these cargoes. In addition, Cheniere Marketing has continued to enter into various business relationships to facilitate purchasing and selling commercial LNG cargoes.

LNGCo Agreements

In March 2010, Cheniere Marketing entered into various agreements ("LNGCo Agreements") with JPMorgan LNG Co. ("LNGCo"), effective April 1, 2010, under which Cheniere Marketing has agreed to develop and maintain commercial and trading opportunities in the LNG industry and present any such opportunities exclusively to LNGCo. Cheniere Marketing also agreed to provide, or arrange for the provision of, all of the operations and administrative services required by LNGCo in connection with any LNG cargoes purchased by LNGCo, including negotiating agreements and arranging for transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the LNGCo Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the LNGCo Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the LNGCo Agreements is two years; however, either party may terminate without penalty at the end of one year. In return for the services to be provided by Cheniere Marketing, LNGCo will pay a fixed fee to Cheniere Marketing and may pay additional fees depending upon the gross margins of each transaction and the aggregate gross margin earned during the term of the LNGCo Agreements.

LNG and Natural Gas Marketing Competition

In purchasing LNG, we compete for supplies of LNG with:


•	large, multinational and national companies with longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources;


•	oil and gas producers who sell or control LNG derived from their international oil and gas properties; and


•	purchasers located in other countries where prevailing market prices can be substantially different from those in the U.S.

In marketing LNG and natural gas, we compete for sales of LNG and natural gas with a variety of competitors including:


•	major integrated marketers who have large amounts of capital to support their marketing operations and offer a full-range of services and market numerous products other than natural gas;


•	producer marketers who sell their own natural gas production or the production of their affiliated natural gas production company;


•	small geographically focused marketers who focus on marketing natural gas for the geographic area in which their affiliated distributor operates; and


•	aggregators who gather small volumes of natural gas from various sources, combine them and sell the larger volumes for more favorable prices and terms than would be possible selling the smaller volumes separately.

LNG and Natural Gas Marketing Governmental Regulation

In 1992 and 1993, the FERC concluded that sellers of short-term or long-term natural gas supplies would not have market power over the sale for resale of natural gas. The FERC established light-handed regulation over sales for resale of natural gas and adopted regulations granting blanket certificates to allow entities selling natural gas to make interstate sales for resale at negotiated rates. In 2003, the FERC amended the blanket marketing certificates to require that all sellers adhere to a code of conduct with respect to natural gas sales. The code of conduct addresses such matters as natural gas withholding, manipulation of market prices, communication of accurate information and record retention.

The EPAct contains provisions intended to prohibit the manipulation of the natural gas markets and is applicable to our LNG, pipeline and natural gas marketing businesses. See “—LNG Terminal Business Governmental Regulation” and "—Natural Gas Pipeline Business—Natural Gas Pipeline Governmental Regulation."

The prices at which we sell natural gas are not regulated, insofar as the interstate market is concerned and, for the most part, are not subject to state regulation. We are permitted to make sales of natural gas for resale in interstate commerce pursuant to a blanket marketing certificate automatically granted by the FERC. Our sales of natural gas will be affected by the availability, terms and cost of pipeline transportation. As noted above, under “—Natural Gas Pipeline Business—Natural Gas Pipeline Governmental Regulation,” the price and terms of access to pipeline transportation are subject to extensive federal and state regulation.

Subsidiaries

Our assets are generally held by or under our operating subsidiaries. We conduct most of our operations through these subsidiaries, including our operations relating to the development and operation of our LNG terminal business, the development and operation of our pipeline business and the development and operation of our LNG and natural gas marketing business.

Employees and Labor Relations

We had 196 full-time employees at February 21, 2011, including 106 employees who directly supported Sabine Pass LNG’s operations. We consider our current employee relations to be favorable.

Available Information

Our principal executive offices are located at 700 Milam Street, Suite 800, Houston, Texas 77002, and our telephone number is (713) 375-5000. Our internet address is http://www.cheniere.com. We provide public access to our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to these reports as soon as reasonably practicable after we electronically file those materials with, or furnish those materials to, the Securities and Exchange Commission (“SEC”) under the Exchange Act. These reports may be accessed free of charge through our internet website. We make our website content available for informational purposes only. The website should not be relied upon for investment purposes and is not incorporated by reference into this Form 10-K.

We will also make available to any stockholder, without charge, copies of our Annual Report on Form 10-K as filed with the SEC. For copies of this, or any other filing, please contact: Cheniere Energy, Inc., Investor Relations Department, 700 Milam Street, Suite 800, Houston, Texas 77002 or call (713) 562-5000. In addition, the public may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Room 1580, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC maintains an internet site (www.sec.gov) that contains reports, proxy and information statements and other information regarding issuers, like us, that file electronically with the SEC.

ITEM 1A. RISK FACTORS

The following are some of the important factors that could affect our financial performance or could cause actual results to differ materially from estimates or expectations contained in our forward-looking statements. We may encounter risks in addition to those described below. Additional risks and uncertainties not currently known to us, or that we currently deem to be immaterial, may also impair or adversely affect our business, results of operation, financial condition, liquidity and prospects.

The risk factors in this report are grouped into the following categories:


•	Risks Relating to Our Financial Matters;


•	Risks Relating to Our LNG Terminal Business;


•	Risks Relating to Our Natural Gas Pipeline Business;


•	Risks Relating to Our LNG and Natural Gas Marketing Business;


•	Risks Relating to Our LNG Businesses in General; and


•	Risks Relating to Our Business in General.

Risks Relating to Our Financial Matters

Our existing level of cash resources, negative operating cash flow and significant debt could cause us to have inadequate liquidity and could materially and adversely affect our business, financial condition and prospects

As of December 31, 2010, we had $74.2 million of cash and cash equivalents and $156.0 million of restricted cash and cash equivalents, and we had $2.9 billion of total debt outstanding on a consolidated basis (before debt discounts). We incur significant depreciation and interest expense relating to the assets at the Sabine Pass LNG terminal, and we may incur significant additional debt and costs in connection with expansion of the Sabine Pass LNG terminal to provide bi-directional service. Our ability to generate positive cash flow and achieve profitability, so as to enhance our liquidity position in the future and be able to repay or refinance our debt, is subject to a number of risks, including those discussed in these Risk Factors.

We have a significant amount of debt which we may be unable to repay, refinance, or extend on commercially reasonable terms or at all, which could materially and adversely affect our business, financial condition and prospects.

As of December 31, 2010, we had $3.0 billion of total consolidated indebtedness (before debt discounts). Approximately $298 million of our debt will mature on May 31, 2012, our earliest debt maturity date. We do not currently have financial resources, and may not be able to access external financial resources, sufficient to enable us to repay our earliest maturing debt or our subsequently maturing debt. If we are unable to refinance, extend or otherwise satisfy our earliest maturing debt, we may seek to reorganize under the protection of available reorganization statutes and may make such a determination at a time prior to our earliest debt maturity date.

Even if we are able to repay, refinance or extend our debt, the terms required may adversely affect us.

In order to obtain many types of financing, we may have to accept terms that are disadvantageous to us or that may have an adverse impact on our current or future business, operations or financial condition. For example:


•	borrowings, debt issuances, or extensions of debt maturities may subject us to certain restrictive covenants, including covenants restricting our ability to raise additional capital or cross-defaults to our other indebtedness;


•	borrowings or debt issuances at the project level may subject the project entity to restrictive covenants, including covenants restricting its ability to make distributions to us or limiting our ability to sell our interests in such entity;


•	offerings of our equity securities could cause substantial dilution for holders of our common stock;


•	additional sales of interests in our projects would reduce our interest in future revenues; and


•	the prepayment of fees by, or a business development loan from, prospective customers would reduce future revenues after a facility commences operations.

Our substantial indebtedness and restrictions contained in existing or future debt agreements could adversely affect our ability to operate our business and pursue our liquefaction project, and could prevent us from satisfying or refinancing our debt obligations.

Our substantial indebtedness and restrictions contained in existing or future debt agreements could have important adverse consequences, including:


•	limiting our ability to attract customers;


•	limiting our ability to compete with other companies that are not as highly leveraged;


•	limiting our flexibility in and ability to plan for or react to changing market conditions in our industry and to economic downturns, and making us more vulnerable than our less leveraged competitors to an industry or economic downturn;


•	limiting our ability to use operating cash flow in other areas of our business because we must dedicate a substantial portion of these funds to service debt, including indebtedness that we may incur in the future;


•	limiting our ability to obtain additional financing to fund the expansion of the Sabine Pass LNG terminal to provide bi-directional service, our capital expenditures, working capital, acquisitions, debt service requirements or liquidity needs for general business or other purposes; and


•	resulting in a material adverse effect on our business, results of operations and financial condition if we are unable to service or refinance our indebtedness or obtain additional financing, as needed.

Our substantial indebtedness and the restrictive covenants contained in our existing or future debt agreements may not allow us the flexibility that we need to operate our business in an effective and efficient manner and may prevent us from taking advantage of strategic and financial opportunities that would benefit our business, such as Cheniere Partners' liquefaction project. If we fail to comply with the restrictions contained in the agreements governing our existing indebtedness or any subsequent financing agreements, a default may allow our creditors, if the agreements so provide, to accelerate the related indebtedness as well as any other indebtedness to which cross-acceleration or cross-default provision applies.

If we are unsuccessful in operating our business or taking advantage of such opportunities, due to our substantial indebtedness or other factors, we may be unable to repay, refinance or extend our indebtedness on commercially reasonable terms or at all.

To service our indebtedness, we require significant amounts of cash flow from operations.

We require significant amounts of cash flow from operations in order to make annual interest payments of approximately $212 million on the Senior Notes, 2007 Term Loan, Convertible Senior Unsecured Notes and 2008 Loans. Our ability to make payments on and to refinance our indebtedness and to fund our capital expenditures will depend on our ability to generate cash in the future. Our business may not generate sufficient cash flow from operations, currently anticipated costs may increase, or future borrowings may not be available to us, which could cause us to be unable to pay or refinance our indebtedness or to fund our other liquidity needs.

Sabine Pass LNG may be restricted under the terms of the Sabine Pass Indenture from making distributions under certain circumstances, which may limit Cheniere Partners' ability to pay or increase distributions to us, which could materially and adversely affect us.

The Sabine Pass Indenture restricts payments that Sabine Pass LNG can make to us in certain events and limits the indebtedness that Sabine Pass LNG can incur. Sabine Pass LNG is permitted to pay distributions to us only after the following payments have been made:


•	an operating account has been funded with amounts sufficient to cover the succeeding 45 days of operating and maintenance expenses, maintenance capital expenditures and obligations, if any, under an assumption agreement and a state tax sharing agreement;


•	one-sixth of the amount of interest due on the Senior Notes on the next interest payment date (plus any shortfall from any such month subsequent to the preceding interest payment date) has been transferred to a debt payment account;


•	outstanding principal on the Senior Notes then due and payable has been paid;


•	taxes payable by Sabine Pass LNG or the guarantors of the Senior Notes and permitted payments in respect of taxes have been paid; and


•	the debt service reserve account has on deposit the amount required to make the next interest payment on the Senior Notes.

In addition, Sabine Pass LNG will only be able to make distributions to us in the event that it could, among other things, incur at least $1.00 of additional indebtedness under the fixed charge coverage ratio test of 2:1 at the time of payment and after giving pro forma effect to the distribution.

Sabine Pass LNG is also prohibited under the Sabine Pass Indenture from paying distributions to us or incurring additional indebtedness upon the occurrence of any of the following events, among others:


•	a default for 30 days in the payment of interest on, or additional interest, if any, with respect to, the Senior Notes;


•	a failure to pay any principal of, or premium, if any, on the Senior Notes;


•	a failure by Sabine Pass LNG to comply with various covenants in the Sabine Pass Indenture;


•	a failure to observe any other agreement in the Sabine Pass Indenture beyond any specified cure periods;


•	a default under any mortgage, indenture or instrument governing any indebtedness for borrowed money by Sabine Pass LNG in excess of $25.0 million if such default results from a failure to pay principal or interest on, or results in the acceleration of, such indebtedness;


•	a final money judgment or decree (not covered by insurance) in excess of $25.0 million is not discharged or stayed within 60 days following entry;


•	a failure of any material representation or warranty in the security documents entered into in connection with the indenture to be correct;


•	the Sabine Pass LNG terminal project is abandoned; or


•	certain events of bankruptcy or insolvency.

Sabine Pass LNG's inability to pay distributions to us or to incur additional indebtedness as a result of the foregoing restrictions in the Sabine Pass Indenture may inhibit our ability to pay or increase distributions to Cheniere Partners unitholders.

The fixed charge coverage ratio test contained in the Sabine Pass Indenture could prevent Sabine Pass LNG from making cash distributions. As a result, Cheniere Partners may be prevented from making distributions to us, which could materially and adversely affect us.

Sabine Pass LNG is not permitted to make cash distributions if its consolidated cash flow is not at least twice its fixed charges, calculated as required in the Sabine Pass Indenture. In order to satisfy this fixed charge coverage ratio test, we estimate that Sabine Pass LNG's consolidated cash flow, as defined in the Sabine Pass Indenture, must be greater than approximately $375 million. Thus, TUA payments from Cheniere Investments are needed in addition to the TUA payments from Chevron and Total. Cheniere Investments has not commercialized its reserved regasification capacity or implemented its liquefaction project and may have difficulty making its TUA payments.

The fixed charge coverage ratio test contained in the Sabine Pass Indenture may not be met if Cheniere Investments' payments to Sabine Pass LNG cease to be recognizable as revenue under U.S. generally accepted accounting principles, or GAAP. Even if Sabine Pass LNG receives the contracted payments under the Cheniere Investments TUA, the fixed charge coverage test will not be satisfied if those payments do not constitute revenues under GAAP, as then in effect. If the fixed charge coverage ratio test is not satisfied, Sabine Pass LNG will not be permitted by the Sabine Indenture to make distributions to Cheniere Partners, which may prevent Cheniere Partners from making distributions to us, which could have a material and adverse effect on our business, results of operations, financial condition and prospects.

Cheniere Partners' ability to pay cash distributions on the common units we hold could be limited if Cheniere Marketing fails to make payments to Cheniere Investments under the VCRA, if Cheniere Investments fails to make payments to Sabine Pass LNG under its TUA, or if Sabine Pass LNG fails to make cash distributions.

Under the VCRA, Cheniere Marketing is required to pay for taxes and new regulatory costs incurred under the Cheniere Investments TUA. Cheniere Marketing is also required to use commercially reasonable efforts to commercialize Cheniere Investments' TUA to the extent that neither Cheniere Marketing nor Cheniere Investments is obligated to the contrary under other agreements. Cheniere Marketing is further obligated to make payments to Cheniere Partners up to a maximum of $1.6 million per year to the extent that Cheniere Partners has a shortfall between its available cash and its initial quarterly distributions to its common unitholders.

In addition, even if Sabine Pass LNG received the contracted payments under the Cheniere Investments TUA, the fixed charge coverage test will not be satisfied if those payments do not constitute revenue under GAAP as then in effect and as provided in the Sabine Pass Indenture. Because the Cheniere Investments TUA is an agreement between related parties, payments under the Cheniere Investments TUA may not constitute revenues under GAAP as currently in effect if Cheniere Investments is determined to lack economic substance apart from Sabine Pass LNG. We believe Cheniere Investments could be determined to lack economic substance apart from Sabine Pass LNG if, for example, Cheniere Investments has no substantive business and is not pursuing, and has no prospect of developing, any substantive business apart from its TUA with Sabine Pass LNG.

If Cheniere Investments does not receive distributions from Sabine Pass LNG, Cheniere Partners may not be able to continue to make distributions to us, which could have a material and adverse effect on our business, results of operations, financial condition and prospects.

Our ability to generate needed amounts of cash is substantially dependent upon our TUAs with two third-party Sabine Pass LNG customers, and we will be materially and adversely affected if either customer fails to perform its TUA obligations for any reason.

Our future results and liquidity are substantially dependent upon performance by Chevron and Total, each of which has entered into a TUA with Sabine Pass LNG and agreed to pay us approximately $125 million annually. We are dependent on each customer's continued willingness and ability to perform its obligations under its TUA. We are also exposed to the credit risk of the guarantors of these customers' obligations under their respective TUAs in the event that we must seek recourse under a guaranty. If either customer fails to perform its obligations under its TUA, our business, results of operations, financial condition and prospects could be materially and adversely affected, even if we were ultimately successful in seeking damages from that customer or its guarantor for a breach of the TUA.

Each customer's TUA for capacity at the Sabine Pass LNG terminal is subject to termination under certain circumstances.

Each of Sabine Pass LNG's long-term TUAs contains various termination rights. For example, each customer may terminate its TUA if the Sabine Pass LNG terminal experiences a force majeure delay for longer than 18 months, fails to redeliver a specified amount of natural gas in accordance with the customer's redelivery nominations or fails to accept and unload a specified number of the customer's proposed LNG cargoes. We may not be able to replace these TUAs on desirable terms, or at all, if they are terminated.

Our ability to generate needed amounts of cash is also dependent upon our ability to commercially exploit the capacity at the Sabine Pass LNG terminal that we have reserved for our own account

Our ability to achieve profitability in the future is significantly dependent upon our ability to commercially exploit the capacity that Cheniere Investments has reserved at the Sabine Pass LNG terminal. As discussed below under “—Risks Relating to Our LNG and Natural Gas Marketing Business," Cheniere Investments may be unable to commercially exploit its capacity at the Sabine Pass LNG terminal. There are significant risks attendant to Cheniere Investments' future ability to generate additional operating cash flow. Failure by Cheniere Investments to succeed in commercially exploiting its reserved capacity at the Sabine Pass LNG terminal could materially and adversely affect our business, results of operations, financial condition and prospects.

In order to generate needed amounts of cash, we may sell equity or equity-related securities or assets, including equity interests in Cheniere Partners. Such sales could dilute our stockholders' proportionate indirect interests in the assets, business operations and proposed liquefaction and other projects of Cheniere Partners or other subsidiaries, and could adversely affect the market price of our common stock.

We have pursued and are pursuing a number of alternatives in order to generate needed amounts of cash, including potential issuances and sales of additional equity or equity-related securities by us, Cheniere Partners, or both, and potential sales of assets, including units of limited partner interest we currently hold in Cheniere Partners. Such sales, in one or more transactions, could dilute our stockholders' proportionate indirect interests in the assets. business operations and proposed projects of Cheniere Partners, including its proposed liquefaction project, or in other subsidiaries. In addition, such sales, or the anticipation of such sales, could adversely affect the market price of our common stock.

We have not been profitable historically, and we have not had positive operating cash flow. Our ability to achieve profitability and generate positive operating cash flow in the future is subject to significant uncertainty.

We had net losses of $76.2 million, $161.5 million and $373.0 million (as adjusted), for the years ended December 31, 2010, 2009 and 2008, respectively. In addition, our net cash flow used in operating activities was $16.9 million, $97.9 million and $142.1 million for the years ended December 31, 2010, 2009 and 2008, respectively. In the future, we may incur operating losses and experience negative operating cash flow. We may not be able to reduce costs, increase revenues, or reduce our debt service obligations sufficiently to maintain our cash resources, which could cause us to have inadequate liquidity to continue our business.

Risks Relating to Our LNG Receiving Terminal Business

Operation of the Sabine Pass LNG terminal, and other LNG terminals that we may construct, involves significant risks.

As more fully discussed in these Risk Factors, the Sabine Pass LNG terminal faces operational risks, including the following:


•	performing below expected levels of efficiency;


•	breakdown or failures of equipment or systems;


•	operational errors by vessel or tug operators or others;


•	operational errors by us or any contracted facility operator or others;


•	labor disputes; and


•	weather-related interruptions of operations.

To maintain the cryogenic readiness of the Sabine Pass LNG terminal, Sabine Pass LNG may need to purchase and process LNG. Sabine Pass LNG's third-party customers have the obligation to procure LNG if necessary for the Sabine Pass LNG terminal to maintain its cryogenic state. If they fail to do so, Sabine Pass LNG may need to procure such LNG.

Sabine Pass LNG needs to maintain the cryogenic readiness of the Sabine Pass LNG terminal. Together with Sabine Pass LNG, the two third-party customers have the obligation to maintain minimum inventory levels, and under certain circumstances, to procure LNG to maintain the cryogenic readiness of the terminal. In the event that aggregate minimum inventory levels are not maintained, Sabine Pass LNG has the right to procure a cryogenic readiness cargo, and to the extent that the third-party customers have failed to maintain their minimum inventory levels, be reimbursed by each customer for their allocable share of the LNG acquisition costs. If Sabine Pass LNG is not able to obtain financing on acceptable terms, it will need to maintain sufficient working capital for such a purchase until it receives reimbursement for the allocable costs of the LNG from its third-party customers or sells the regasified LNG. Sabine Pass LNG may also bear commodity price and other risks of purchasing LNG, holding it in its inventory for a period of time and selling the regasified LNG.

Sabine Pass LNG may be required to purchase natural gas to provide fuel at the Sabine Pass LNG terminal, which would increase operating costs and could have a material adverse effect on our results of operations.

Sabine Pass LNG's TUAs provide for an in-kind deduction of 2% of the LNG delivered to the Sabine Pass LNG terminal, which it uses primarily as fuel for revaporization and self-generated power and to cover natural gas unavoidably lost at the facility. There is a risk that this 2% in-kind deduction will be insufficient for these needs and that Sabine Pass LNG will have to purchase additional natural gas from third parties. Sabine Pass LNG will bear the cost and risk of changing prices for any such fuel.

Hurricanes or other disasters could adversely affect us.

In August and September of 2005, Hurricanes Katrina and Rita damaged coastal and inland areas located in Texas, Louisiana, Mississippi and Alabama. Construction at the Sabine Pass LNG terminal site was temporarily suspended in connection with Hurricane Katrina, as a precautionary measure. Approximately three weeks after the occurrence of Hurricane Katrina, the Sabine Pass LNG terminal site was again secured and evacuated in anticipation of Hurricane Rita, the eye of which made landfall to the east of the site. As a result of these 2005 storms and related matters, the Sabine Pass LNG terminal experienced construction delays and increased costs. In September 2008, Hurricane Ike struck the Texas and Louisiana coast, and we experienced damage at the Sabine Pass LNG terminal.

Future storms and related storm activity and collateral effects, or other disasters such as explosions, fires, floods or accidents, could result in damage to, or interruption of operations at, the Sabine Pass LNG terminal or related infrastructure, as well as delays or cost increases in the construction of Cheniere Partners' proposed liquefaction facilities or our other LNG terminals. If there are changes in the global climate, storm frequency and intensity may increase; should it result in rising seas, our coastal operations would be impacted.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development, construction and operation of our LNG terminals could impede operations and construction and could have a material adverse effect on us.

The design, construction and operation of LNG terminals is a highly regulated activity. The FERC's approval under Section 3 of the NGA, as well as several other material governmental and regulatory approvals and permits, are required in order to construct and operate an LNG terminal. Although Sabine Pass LNG has obtained all of the necessary authorizations to operate the Sabine Pass LNG terminal, such authorizations are subject to ongoing conditions imposed by regulatory agencies, and additional approval and permit requirements may be imposed.

Cheniere Partners and its subsidiaries will require governmental approvals and authorizations to implement the proposed business strategy to construct and operate a liquefaction and LNG export facility at the Sabine Pass LNG terminal site. In particular, Cheniere Partners and its subsidiaries will need authorization from the FERC to construct and operate the proposed liquefaction facilities. In addition, although Sabine Liquefaction has received an order from the DOE permitting it to export natural gas to the FTA countries, Sabine Liquefaction is seeking to expand the permit to allow export to non-FTA countries.

There is no assurance that Cheniere Partners and its subsidiaries will obtain and maintain these governmental permits, approvals and authorizations, and failure to obtain and maintain any of these permits, approvals or authorizations could have a material adverse effect on our business, results of operations, financial condition and prospects.

We may not be able to enter into satisfactory commercial arrangements with third-party customers for services at the Sabine Pass LNG terminal or at our other proposed LNG terminals. We may change our business strategy regarding how and when we market LNG terminal capacity.

We have historically entered into long-term TUAs for a portion of the regasification capacity at our proposed LNG terminals, which include fixed-fee capacity reservation fees. The portion of our total regasification capacity that we plan to commit under such long-term TUAs has changed in the past and may change in the future for various reasons, including responding to market factors or perceived opportunities that we believe may be available to us.

Our ability to obtain financing for Cheniere Partners' proposed liquefaction facilities or our other LNG facilities is expected to be contingent upon, among other things, our ability to enter into sufficient long-term commercial agreements in advance of the commencement of construction. To date, we have not entered into any definitive third-party agreements for Cheniere Partners' proposed liquefaction facilities or either of our proposed LNG terminals, and we may not be successful in negotiating such agreements.

We may also change our business strategy due to our inability to enter into agreements with customers or based on our views regarding future prices, demand and supply of LNG, natural gas, liquefaction capacity and regasification capacity. If our efforts to market LNG terminal and related pipeline capacity are not successful, our business, results of operations, financial condition and prospects could be materially and adversely affected.

The construction of Cheniere Partners' expansion project to add liquefaction capacity at the Sabine Pass LNG terminal will be subject to a number of development risks, which could cause cost overruns and delays or prevent completion of the project.

Key factors that may affect the timing of, and our ability to complete, the expansion project at the Sabine Pass LNG terminal to add bi-directional service include, but are not limited to:


•	the issuance and/or continued availability of necessary permits, licenses and approvals from the FERC and the DOE, other governmental agencies and third parties as are required to construct and operate the expansion project;


•	the availability of sufficient financing on reasonable terms;


•	our ability to obtain satisfactory long-term agreements with customers for bi-directional service and for these customers to perform under those agreements during the terms thereof and to maintain their creditworthiness;


•	our ability to enter into a satisfactory agreement with an EPC and other contractors and to maintain good relationships with these contractors in order to construct the liquefaction facilities, and the ability of those contractors to perform their obligations under the contracts and to maintain their creditworthiness;


•	unanticipated changes in domestic and international market demand for and supply of natural gas and LNG, which will depend, in part, on supplies of, and prices for, alternative energy sources and the discovery of new sources of natural resources;


•	competition with other domestic and international LNG terminals;


•	local and general economic conditions;


•	catastrophes, such as explosions, fires and product spills;


•	resistance in the local community to the expansion of the Sabine Pass LNG terminal;


•	labor disputes; and


•	weather conditions, such as hurricanes.

Delays in the construction of the Sabine Pass LNG expansion project beyond the estimated development periods, as well as cost overruns, could increase the cost of completion beyond the amounts that we estimate, which could require us to obtain additional sources of financing to fund our operations until the expansion project is constructed (which could cause further delays). Any delay in completion of the expansion project may also cause a delay in the receipt of revenues projected from the expansion project or cause a loss of one or more customers in the event of significant delays. As a result, any significant construction delay, whatever the cause, could have a material adverse effect on our business, results of operations, financial condition and prospects.

We may not be successful in implementing our proposed business strategy to provide liquefaction services at the Sabine Pass LNG terminal.

Our proposed addition of liquefaction facilities and services at the Sabine Pass LNG terminal will require very significant financial resources, which may not be available on terms reasonably acceptable to us or at all. Costs overruns or delays could adversely affect permitting or construction of the liquefaction facilities. We also may not be able to obtain customer commitments to use the liquefaction services, without which we would not be able to finance the construction of liquefaction facilities. Even if successfully constructed, the liquefaction facilities would be subject to may of the same operating risks described herein with respect to the Sabine Pass LNG terminal. Accordingly, there are many risks associated with our proposed liquefaction facilities, and we may not be successful implementing our business strategy, which could have a material adverse impact on our business, results of operations, financial condition, liquidity and prospects.

The operation of the Sabine Pass LNG terminal and the liquefaction project are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses that could have a material and adverse effect on us.

The operation of the Sabine Pass LNG terminal and the liquefaction project are subject to the inherent risks associated with this type of operation, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of the Sabine Pass LNG terminal site and assets or damage to persons and property. In addition, operations at the Sabine Pass LNG terminal site and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

We do not, nor do we intend to, maintain insurance against all of these risks and losses. We may not be able to maintain desired or required insurance in the future at rates that we consider reasonable. The occurrence of a significant event not fully insured or indemnified against could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating costs and restrictions

Our business is and will be subject to extensive federal, state and local laws and regulations that control, among other things, discharges to air and water; the handling, storage and disposal of hazardous chemicals, hazardous waste, and petroleum products; and remediation associated with the release of hazardous substances. Many of these laws and regulations, such as the CAA, the Oil Pollution Act, the CWA and the RCRA, and analogous state laws and regulations, restrict or prohibit the types, quantities and concentration of substances that can be released into the environment in connection with the construction and operations of the Sabine Pass OLNG terminal and liquefaction facilities and require us to maintain permits and provide governmental authorities with access to our facilities for inspection and reports related to our compliance. Violation of these laws and regulations could lead to substantial fines and penalties or to capital expenditures related to pollution control equipment that could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects. Federal and state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of an LNG terminal or liquefaction facility, we could be liable for the costs of cleaning up hazardous substances released into the environment and for damage to natural resources.

There are numerous regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. For example, the adoption of frequently proposed legislation implementing a carbon tax on energy sources that emit carbon dioxide into the atmosphere may have a material adverse effect on the ability of our customers (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at the Sabine Pass LNG terminal this carbon tax may also be imposed on us directly.

Risks Relating to Our Natural Gas Pipeline Business

Our existing and proposed pipelines will be dependent upon a few potential customers, and our pipeline business could be materially and adversely affected if we lost any one of those customers.

We do not currently have any third-party, firm transportation customers for our existing or proposed pipelines. Failure to obtain any third-party, firm transportation customers could have a material adverse impact on our business.

Our natural gas pipelines, including their FERC gas tariffs, are subject to FERC regulation.

Our FERC tariffs contain pro forma transportation agreements, which must be filed and approved by the FERC. Before we enter into a transportation agreement with a shipper that contains a term that materially deviates from our tariff, we must seek FERC approval. The FERC may approve the material deviation in the transportation agreement; however, in that case, the materially deviating terms must be made available to our other similarly-situated customers. If we fail to seek FERC approval of a transportation agreement that materially deviates from our tariff, or if the FERC audits our contracts and finds deviations that appear to be unduly discriminatory, the FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should we fail to comply with all applicable FERC-administered statutes, rules, regulations and orders, we could be subject to substantial penalties and fines. Under the EPAct, the FERC has civil penalty authority under the NGA to impose penalties for current violations of up to $1.0 million per day for each violation.

The FERC could change its current ratemaking policies, and those changes could have adverse effects on our proposed pipelines.

Pipeline safety integrity programs and repairs may impose significant costs and liabilities on us.

The Federal Office of Pipeline Safety has issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate certain areas along their pipelines and to take additional measures to protect pipeline segments located in what the rule refers to as “high consequence areas” where a leak or rupture could potentially do the most harm. The final rule requires operators to:


•	perform ongoing assessments of pipeline integrity;


•	identify and characterize applicable threats to pipeline segments that could impact a high consequence area;


•	improve data collection, integration and analysis;


•	repair and remediate the pipeline as necessary; and


•	implement preventive and mitigating actions.

We are required to maintain pipeline integrity testing programs that are intended to assess pipeline integrity. The rule, or an increase in public expectations for pipeline safety, may require additional reporting and more frequent inspection or testing of our pipeline facilities. Any repair, remediation, preventative or mitigating actions may require significant capital and operating expenditures. Should we fail to comply with the Office of Pipeline Safety's rules and related regulations and orders, we could be subject to penalties and fines.

Any reduction in the capacity of, or the allocations to, interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

We will be dependent upon third-party pipelines and other facilities to provide delivery options to and from our pipelines. If any pipeline connection were to become unavailable for volumes of natural gas due to repairs, damage to the facility, lack of capacity or any other reason, our ability to continue shipping natural gas to end markets could be restricted, thereby reducing our revenues. Any permanent interruption at any key pipeline interconnect which caused a material reduction in volumes transported on our pipelines could have a material adverse effect on our business, results of operations and financial condition.

Failure to obtain and maintain approvals and permits from governmental and regulatory agencies with respect to the development and operation of our natural gas pipelines would have a detrimental effect on us and our pipeline projects.

The design, construction and operation of natural gas pipelines and the transportation of natural gas are all highly regulated activities. FERC approval under Section 7 of the NGA, as well as several other material state governmental and regulatory approvals and permits, are required in order to construct and operate a pipeline. We must also obtain several other material governmental and regulatory approvals and permits in order to construct and operate pipelines, including several under the CAA and the CWA from the U.S. Army Corps of Engineers and state environmental agencies. We have no control over the timing of the review and approval process nor can we predict the outcome of the process. We do not know whether or when any such approvals or permits can be obtained, or whether or not any third parties will attempt to interfere with our ability to obtain and maintain such permits or approvals. If we are unable to obtain and maintain the necessary approvals and permits, we may not be able to recover our investment in the projects. Failure to obtain and maintain any of these approvals and permits could have a material adverse effect on our business, results of operations, financial condition and prospects.

Our pipeline business could be materially and adversely affected if we lose the right to situate our pipelines on property owned by third parties.

We do not own the land on which our pipelines are situated, and we are subject to the possibility of increased costs to retain necessary land use rights. If we were to lose these rights or be required to relocate our pipelines, our business could be materially and adversely affected.

Risks Relating to Our LNG and Natural Gas Marketing Business

We may be unable to commercially exploit Cheniere Investments' regasification capacity at the Sabine Pass LNG terminal.

Our ability to commercially exploit Cheniere Investments' reserved capacity will depend upon whether we can successfully enter into TUAs for some or all of the reserved capacity, enter into term LNG purchase agreements for the reserved capacity, or purchase spot cargoes. We will encounter significant competition and may encounter many expenses, delays, problems and difficulties that we have not anticipated and for which we have not planned in our efforts to commercially exploit Cheniere Investments' reserved TUA regasification capacity. Our success in commercially exploiting the TUA capacity that Cheniere Investments has reserved at the Sabine Pass LNG terminal is subject to substantial risks, including the following:


•	we do not have unconditional agreements or arrangements for any supplies of LNG or for the utilization of Cheniere Investments' reserved regasification capacity, and we may not be able to obtain such agreements or arrangements on economical terms, or at all;


•	we do not have unconditional commitments from customers for the purchase of the LNG or natural gas that we propose to sell from the Sabine Pass LNG terminal, and we may not be able to obtain commitments or other arrangements on economical terms, or at all;


•	in order to arrange for supplies of LNG, and for transportation, storage and sales of natural gas, we will require significant credit support and funding, which we may not be able to obtain on terms that are acceptable to us, or at all; and

•

even if we are able to arrange for and finance supplies and transportation of LNG to the Sabine Pass LNG terminal, and for transportation, storage and sales of natural gas to customers, we may experience negative cash flows and adverse liquidity effects due to fluctuations in supply, demand and price for LNG, for transportation of LNG, for natural gas and for storage and transportation of natural gas.

Our success may also be limited by access to capital and Cheniere Marketing's and Cheniere Investments' lack of credit ratings. These factors create financial obstacles and exacerbate the risk that we will not be able to enter into commercial arrangements with third parties to commercially exploit all of the reserved regasification capacity at the Sabine Pass LNG terminal on commercially advantageous terms or at all.

Any or all of these factors, as well as risk factors described elsewhere herein and other risk factors that we may not be able to anticipate, control or mitigate, could have a material adverse effect on our ability to commercially exploit Cheniere Investments' reserved regasification capacity at the Sabine Pass LNG terminal, which in turn could materially and adversely affect our business, results of operations, financial condition, prospects and liquidity.

Our use of hedging arrangements may adversely affect our future results of operations or liquidity.

To reduce our exposure to fluctuations in the price, volume and timing risk associated with the marketing of LNG and natural gas, we use futures, swaps and option contracts traded or cleared on the Intercontinental Exchange (ICE) and NYMEX, or over-the-counter options and swaps with other natural gas merchants and financial institutions. Hedging arrangements would expose us to risk of financial loss in some circumstances, including when:


•	expected supply is less than the amount hedged;


•	the counterparty to the hedging contract defaults on its contractual obligations; or


•	there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received.

Our hedging arrangements may also limit the benefit that we would receive from increases in the prices for natural gas. The use of derivatives also may require the posting of cash collateral with counterparties, which can impact working capital when commodity prices change.

The limited capital resources and credit available to our LNG and natural gas marketing business may limit our ability to develop that business.

We have limited capital available to our LNG and natural gas marketing business. The business also currently has limited access to third-party sources of financing. Other investment-grade marketing companies have greater financial resources than we do. Our LNG and natural gas marketing business continues to develop and implement its business strategy and may not generate sufficient revenues and cash flows to cover the significant fixed costs of the business.

Our exposure to the performance and credit risks of counterparties under agreements may adversely affect our results of operations, liquidity and access to financing.

Our LNG and natural gas marketing business involves our entering into various purchase and sale, hedging and other transactions with numerous third parties (commonly referred to as “counterparties”). In such arrangements, we are exposed to the performance and credit risks of our counterparties, including the risk that one or more counterparties fails to perform its obligation to make deliveries of commodities and/or to make payments. These risks may increase during periods of commodity price volatility. Defaults by suppliers and other counterparties may adversely affect our results of operations, liquidity and access to financing.

Risks Relating to Our LNG Businesses in General

Failure of imported LNG to be a competitive source of energy for North American markets could adversely affect TUA customers and could materially and adversely affect our business, results of operations, financial condition and prospects.

The success of the regasification component of our LNG terminal business, our natural gas pipeline business and our LNG and natural gas marketing business (collectively, our “LNG businesses”) is primarily dependent upon LNG being a competitive source of energy in North America. In North America, due mainly to a historically abundant supply of natural gas and recent discoveries of substantial quantities of unconventional, or shale, natural gas, imported LNG has not developed into a significant energy source. The success of the regasification services component of our business plan is dependent, in part, on the extent to which LNG can, for significant periods and in significant volumes, be produced internationally and delivered to North America at a lower cost than the cost to produce some domestic supplies of natural gas, or other alternative energy sources. Through the use of improved exploration technologies, additional sources of natural gas have recently been and may continue to be discovered in North America, which could further increase the available supply of natural gas and could result in natural gas being available at a lower cost than imported LNG. In addition to natural gas, LNG also competes in North America with other sources of energy, including coal, oil, nuclear, hydroelectric, wind and solar energy.

Other continents have a longer history of importing LNG and, due to their geographic proximity to LNG producers and limited pipeline access to natural gas supplies, may be willing and able to pay more for LNG, thereby reducing or eliminating the supply of LNG available in North American markets. Current and futures prices for natural gas in markets that compete with North America have been higher than prices for natural gas in North America, which has adversely affected the volume of LNG imports into North America. If LNG deliveries to North America continue to be constrained due to stronger demand from these competing markets, our ability and the ability of existing and prospective third-party TUA customers to import LNG into North

America on a profitable basis may be adversely affected.

Political instability in foreign countries that have supplies of natural gas, or strained relations between such countries and the U.S., may also impede the willingness or ability of LNG suppliers and merchants in such countries to export LNG to the U.S. Furthermore, some foreign suppliers of LNG may have economic or other reasons to direct their LNG to non-U.S. markets or to competitors' LNG terminals in the U.S.

As a result of these and other factors, LNG may not be a competitive source of energy in North America. The failure of LNG to be a competitive supply alternative to domestic natural gas, oil and other alternative energy sources could adversely affect our ability to enter into additional TUAs with customers and could also impede the ability to import LNG into North America on a commercial basis by us and our TUA customers, which could inhibit our growth and cause us operating losses. Any significant impediment to the ability to import LNG into the United States generally or to our LNG terminals specifically could have a material adverse effect on us, on our customers and on our business, results of operations, financial condition and prospects.

Decreases in the demand for and price of natural gas could lead to reduced development of LNG projects worldwide, which could adversely affect the regasification component of our LNG businesses and the performance of our customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The development of domestic LNG terminals and LNG projects generally is based on assumptions about the future price of natural gas and the availability of natural gas. Natural gas prices have been, and are likely to continue to be, volatile and subject to wide fluctuations in response to one or more of the following factors:


•	relatively minor changes in the supply of, and demand for, natural gas in relevant markets;


•	political conditions in natural gas producing regions;


•	the extent of domestic production and importation of natural gas in relevant markets;


•	the level of demand for LNG and natural gas in relevant markets, including the effects of economic downturns or upturns;


•	weather conditions;


•	the competitive position of natural gas as a source of energy compared with other energy sources; and


•	the effect of government regulation on the production, transportation and sale of natural gas.

Adverse trends or developments affecting any of these factors could result in decreases in the price of natural gas, leading to reduced development of LNG projects worldwide. Such reductions could adversely affect the regasification component of our LNG businesses and the performance of our customers and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Cyclical or other changes in the demand for LNG capacity may adversely affect our LNG businesses and the performance of our customers and could reduce our operating revenues and may cause us operating losses.

The economics of our LNG businesses could be subject to cyclical swings, reflecting alternating periods of under-supply and over-supply of LNG import or export capacity and available natural gas, principally due to the combined impact of several factors, including:


•	additions to competitive regasification capacity in North America, Europe, Asia and other markets, which could divert LNG from our existing and proposed LNG terminals;


•	competitive liquefaction capacity in North America, which could divert natural gas from our proposed liquefaction facilities at our existing and proposed LNG terminals;


•	insufficient or oversupply of LNG liquefaction or receiving capacity worldwide;


•	insufficient LNG tanker capacity;


•	reduced demand and lower prices for natural gas;


•	increased natural gas production deliverable by pipelines, which could suppress demand for LNG;


•	cost improvements that allow competitors to offer LNG regasification or liquefaction services at reduced prices;


•	changes in supplies of, and prices for, alternative energy sources such as coal, oil, nuclear, hydroelectric, wind and solar energy, which may reduce the demand for natural gas;


•	changes in regulatory, tax or other governmental policies regarding imported or exported LNG, natural gas or alternative energy sources, which may reduce the demand for imported or exported LNG and/or natural gas;


•	adverse relative demand for LNG compared to other markets, which may decrease LNG imports into or exports from North America; and


•	cyclical trends in general business and economic conditions that cause changes in the demand for natural gas.

These factors could materially and adversely affect our ability, and the ability of our current and prospective customers, to procure supplies of LNG to be imported into North America and to procure customers for LNG or regasified LNG at economical prices, or at all.

Our LNG businesses face competition, including competing LNG terminals and related pipelines, from competitors with far greater resources.

Many competing companies have secured access to, or are pursuing development or acquisition of, LNG facilities to serve the North American natural gas market, including other proposed liquefaction facilities in North America. Competitors faced by our LNG purchase, importation, regasification, storage, transportation and sale businesses in North America include major energy companies. In addition, competitors have developed or reopened additional LNG terminals in Europe, Asia and other markets, which also compete with our existing and proposed LNG facilities. We may also face competition from major energy companies and others in pursuing our proposed business strategy to provide liquefaction and export services at the Sabine Pass LNG terminal. Almost all of these competitors have longer operating histories, more development experience, greater name recognition, larger staffs and substantially greater financial, technical and marketing resources and access to natural gas and LNG supplies than we do. The superior resources that these competitors have available for deployment could allow them to compete successfully against our LNG businesses, which could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Insufficient development of additional LNG liquefaction and regasification capacity worldwide could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

Commercial development of an LNG facility, including the proposed expansion of the Sabine Pass LNG terminal to add bi-directional service, takes a number of years and requires substantial capital investment. Many factors could negatively affect continued development of LNG facilities, including:


•	increased construction costs;


•	economic downturns, increases in interest rates or other events that may affect the availability of sufficient financing for LNG projects on commercially reasonable terms;


•	decreases in the price of LNG and natural gas, which might decrease the expected returns relating to investments in LNG projects;


•	the inability of project owners or operators to obtain governmental approvals to construct or operate LNG facilities;


•	political unrest or local community resistance to the siting of LNG facilities due to safety, environmental or security concerns; and


•	any significant explosion, spill or similar incident involving an LNG facility or LNG vessel.

There may be shortages of LNG vessels worldwide, which could adversely affect our LNG businesses and could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

The construction and delivery of LNG vessels require significant capital and long construction lead times, and the availability of the vessels could be delayed to the detriment of our LNG businesses and our customers because of:


•	an inadequate number of shipyards constructing LNG vessels and a backlog of orders at these shipyards;


•	political or economic disturbances in the countries where the vessels are being constructed;


•	changes in governmental regulations or maritime self-regulatory organizations;


•	work stoppages or other labor disturbances at the shipyards;


•	bankruptcy or other financial crisis of shipbuilders;


•	quality or engineering problems;


•	weather interference or a catastrophic event, such as a major earthquake, tsunami or fire; and


•	shortages of or delays in the receipt of necessary construction materials.

Terrorist attacks or military campaigns may adversely impact our LNG businesses.

A terrorist or military incident involving an LNG facility or LNG carrier may result in delays in, or cancellation of, construction of new LNG facilities, including our LNG terminals and related natural gas pipelines and proposed liquefaction facilities, which would increase our costs and decrease our cash flows. A terrorist incident may also result in temporary or permanent closure of existing LNG facilities, which could increase our costs and decrease our cash flows, depending on the duration of the closure. Operations at our LNG facilities could also become subject to increased governmental scrutiny that may result in additional security measures at a significant incremental cost to us. In addition, the threat of terrorism and the impact of military campaigns may lead to continued volatility in prices for natural gas that could adversely affect our LNG businesses and our customers, including their ability to satisfy their obligations to us under the commercial agreements.

Risks Relating to Our Business in General

We are subject to significant operating hazards and uninsured risks, one or more of which may create significant liabilities and losses for us.

The construction and operation of our LNG terminals, liquefaction facilities and pipelines are subject to the inherent risks associated with these types of operations, including explosions, pollution, release of toxic substances, fires, hurricanes and adverse weather conditions, and other hazards, each of which could result in significant delays in commencement or interruptions of operations and/or in damage to or destruction of our facilities or damage to persons and property. In addition, our operations and the facilities and vessels of third parties on which our operations are dependent face possible risks associated with acts of aggression or terrorism.

Existing and future environmental and similar laws and regulations could result in increased compliance costs or additional operating costs and restrictions.

effect on our business, results of operations, financial condition, liquidity and prospects. CERCLA and similar state laws impose liability, without regard to fault or the lawfulness of the original conduct, for the release of certain types or quantities of hazardous substances into the environment. As the owner and operator of an LNG terminal, liquefaction facility or pipeline, we could be liable for the costs of cleaning up hazardous substances released into the environment and for damage to natural resources.

There are numerous regulatory approaches currently in effect or being considered to address greenhouse gases, including possible future U.S. treaty commitments, new federal or state legislation that may impose a carbon emissions tax or establish a cap-and-trade program, and regulation by the EPA. For example, the adoption of frequently proposed legislation implementing a carbon tax on energy sources that emit carbon dioxide into the atmosphere may have a material adverse effect on the ability of our customers (i) to import LNG, if imposed on them as importers of potential emission sources, or (ii) to sell regasified LNG, if imposed on them or their customers as natural gas suppliers or consumers. In addition, as we consume retainage gas at the Sabine Pass LNG terminal, this carbon tax may also be imposed on us directly.

Other future legislation and regulations, such as those relating to the transportation and security of LNG imported to or exported from the Sabine Pass LNG terminal through the Sabine Pass Channel, could cause additional expenditures, restrictions and delays in our business and to our proposed construction, the extent of which cannot be predicted and which may require us to limit substantially, delay or cease operations in some circumstances. Revised, reinterpreted or additional laws and regulations that result in increased compliance costs or additional operating costs and restrictions could have a material adverse effect on our business, results of operations, financial condition, liquidity and prospects.

We may experience increased labor costs, and the unavailability of skilled workers or our failure to attract and retain key personnel could adversely affect us.

We are dependent upon the available labor pool of skilled employees. We compete with other energy companies and other employers to attract and retain qualified personnel with the technical skills and experience required to construct and operate our LNG terminals, liquefaction facilities and pipelines and to provide our customers with the highest quality service. A shortage in the labor pool of skilled workers or other general inflationary pressures or changes in applicable laws and regulations could make it more difficult for us to attract and retain personnel and could require an increase in the wage and benefits packages that we offer, thereby increasing our operating costs. For example, in the aftermaths of Hurricanes Katrina and Rita, Bechtel and certain subcontractors temporarily experienced a shortage of available skilled labor necessary to meet the requirements of the Sabine Pass LNG terminal construction plan. As a result, we agreed to change orders with Bechtel concerning additional activities and expenditures to mitigate the hurricanes' effects on the construction of the Sabine Pass LNG terminal. Any increase in our operating costs could materially and adversely affect our business, results of operations, financial condition and prospects.

We depend on our executive officers for various activities. We do not maintain key person life insurance policies on any of our personnel. Although we have arrangements relating to compensation and benefits with certain of our executive officers, we do not have any employment contracts or other agreements with key personnel binding them to provide services for any particular term. The loss of the services of any of these individuals could seriously harm us.

Our lack of diversification could have an adverse effect on our financial condition and results of operations.

Substantially all of our anticipated revenue in 2011 will be dependent upon one facility, the Sabine Pass LNG terminal and related pipeline located in southern Louisiana. Due to our lack of asset and geographic diversification, an adverse development at the Sabine Pass LNG terminal or pipeline, or in the LNG industry, would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets and operating areas.

We may engage in operations or make substantial commitments and investments located, or enter into agreements with counterparties located, outside the United States, which would expose us to political, governmental and economic instability and foreign currency exchange rate fluctuations.

Conducting operations or making commitments and investments located, or enter into agreements with counterparties located, outside of the United States will cause us to be affected by economic, political and governmental conditions in the countries where we engage in business. Any disruption caused by these factors could harm our business. Risks associated with operations, commitments and investments outside of the United States include risks of:


•	currency fluctuations;


•	war;


•	expropriation or nationalization of assets;


•	renegotiation or nullification of existing contracts;


•	changing political conditions;


•	changing laws and policies affecting trade, taxation and investment;


•	multiple taxation due to different tax structures; and


•	the general hazards associated with the assertion of sovereignty over certain areas in which operations are conducted.

Because our reporting currency is the United States dollar, any of our operations conducted outside the United States or denominated in foreign currencies would face additional risks of fluctuating currency values and exchange rates, hard currency shortages and controls on currency exchange. We would be subject to the impact of foreign currency fluctuations and exchange rate changes on our reporting for results from those operations in our consolidated financial statements.

We may incur impairments to goodwill or long-lived assets.

We review our long-lived assets, including goodwill and other intangible assets, for impairment annually in the fourth quarter or whenever events or changes in circumstances indicate that the carrying amount of these assets may not be recoverable. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill and other intangible assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment to our goodwill, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our results of operations.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 3. LEGAL PROCEEDINGS

We may in the future be involved as a party to various legal proceedings, which are incidental to the ordinary course of business. We regularly analyze current information and, as necessary, provide accruals for probable liabilities on the eventual disposition of these matters. In the opinion of management, as of December 31, 2010, there were no threatened or pending legal matters that would have a material impact on our consolidated results of operations, financial position or cash flows.

ITEM 4. (REMOVED AND RESERVED)

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common stock has traded on the NYSE Amex Equities under the symbol LNG since March 24, 2003. The table below presents the high and low daily closing sales prices of the common stock, as reported by the NYSE Amex Equities, for each quarter during 2009 and 2010.


	High		Low
Three Months Ended
March 31, 2009	$	4.98	$	3.01
June 30, 2009	5.19		2.71
September 30, 2009	3.47		2.50
December 31, 2009	2.95		1.80
Three Months Ended
March 31, 2010	$	3.55	$	2.49
June 30, 2010	5.20		2.55
September 30, 2010	3.04		2.36
December 31, 2010	6.20		2.63

As of February 21, 2011, we had 69.7 million shares of common stock outstanding held by approximately 336 record owners.

We have never paid a cash dividend on our common stock. We currently intend to retain earnings to finance the growth and development of our business and do not anticipate paying any cash dividends on the common stock in the foreseeable future. Any future change in our dividend policy will be made at the discretion of our board of directors in light of our financial condition, capital requirements, earnings, prospects and any restrictions under any financing agreements, as well as other factors the board of directors deems relevant.

Issuer Purchases of Equity Securities

During the twelve months ended December 31, 2010, we purchased 605,000 shares of restricted stock at an average cash price of $4.70 per share related to restricted stock that vested during 2010 and that was returned to the Company by employees to cover taxes.

Total Stockholder Return

The following graph compares the cumulative total stockholder return on our common stock against the S&P Oil and Gas Exploration and Production Index, and the Russell 2000 Index for the five years ending December 31, 2010. The graph was constructed on the assumption that $100 was invested in our common stock, the S&P Oil & Gas Exploration & Production Index and the Russell 2000 Index on December 31, 2005 and that any dividends were fully reinvested.


Company / Index	2006		2007		2008		2009		2010
Cheniere Energy, Inc.	$	7	$	88	$	8	$	7	$	15
Russell 2000 Index	$	118	$	117	$	77	$	98	$	124
S&P Oil & Gas Exploration & Production	$	105	$	151	$	99	$	141	$	154

ITEM 6. SELECTED FINANCIAL DATA

Selected financial data set forth below are derived from our audited Consolidated Financial Statements for the periods indicated. The financial data should be read in conjunction with Management’s Discussion and Analysis of Financial Condition and Results of Operations and our Consolidated Financial Statements and Notes thereto included elsewhere in this report.


	Year Ended December 31,
	(in thousands, except per share data)
	2010			2009			2008			2007			2006
Revenues	$	291,513		$	181,126		$	7,144		$	647		$	2,371
LNG terminal and pipeline development expenses	11,971			223			10,556			34,656			12,099
LNG terminal and pipeline operating expenses	42,415			36,857			14,522			—			—
Oil and gas production and exploration costs	627			471			526			1,474			3,375
Depreciation, depletion and amortization	63,251			54,229			24,346			6,393			3,131
General and administrative expenses (1)	68,626			65,830			122,678			122,046			58,012
Restructuring charges (2)	—			20			78,704			—			—
Income (loss) from operations	104,623			23,496			(244,188		)	(163,940		)	(75,874		)
Gain (loss) from equity method investments (3)	128,330			—			(4,800		)	(191		)	—
Gain (loss) on early extinguishment of debt (4)	(50,320		)	45,363			(10,691		)	—			(43,159		)
Derivative gain (loss) (5)	461			5,277			4,652			—			(20,070		)
Interest expense, net	(262,046		)	(243,295		)	(147,136		)	(119,360		)	(67,252		)
Interest income	534			1,405			20,337			82,635			49,087
Non-controlling interest	2,191			6,165			8,777			3,425			—
Net loss	(76,203		)	(161,490		)	(372,959		)	(196,580		)	(159,137		)
Net loss per share (basic and diluted)	$	(1.37	)	$	(3.13	)	$	(7.87	)	$	(3.89	)	$	(2.92	)
Weighted average shares outstanding (basic and diluted)	55,765			51,598			47,365			50,537			54,423


	December 31,
	2010			2009			2008			2007			2006
Cash and cash equivalents	$	74,161		$	88,372		$	102,192		$	296,530		$	462,963
Restricted cash and cash equivalents (current)	73,062			138,309			301,550			228,085			176,827
Working capital	99,276			220,063			350,459			427,511			588,034
Non-current restricted cash and cash equivalents	82,892			82,892			138,483			478,225			1,071,722
Non-current restricted U.S. Treasury securities	—			—			20,829			63,923			—
Property, plant and equipment, net	2,157,597			2,216,855			2,170,158			1,645,112			748,818
Debt issuances costs, net	41,656			47,043			55,688			41,449			38,422
Goodwill	76,819			76,819			76,844			76,844			76,844
Total assets	2,553,507			2,732,622			2,920,082			2,959,743			2,601,365
Long-term debt, net of discount	2,918,579			2,692,740			2,750,308			2,657,579			2,242,209
Long-term debt—related parties, net of discount	8,930			349,135			332,054			—			—
Long-term deferred revenue	29,994			33,500			37,500			40,000			41,000
Total liabilities	3,026,117			3,164,749			3,194,136			2,879,317			2,346,450
Total stockholders’ equity (deficit)	$	(472,610	)	$	(649,732	)	$	(524,216	)	$	(205,249	)	$	254,915


(1)	General and administrative expenses include $16.1 million, $19.2 million, $55.0 million, $56.6 million, and $20.2 million share-based compensation expense recognized in the years ended December 31, 2010, 2009. 2008, 2007, and 2006 respectively.


(2)	In the second quarter of 2008, we announced a cost savings program in connection with the downsizing of our natural gas marketing business activities, the nearing completion of significant construction activities for both the Sabine Pass LNG terminal and Creole Trail Pipeline and the seeking of alternative arrangements for our time charter interest in two LNG vessels.


(3)	In 2010, our investment in Freeport LNG Development, L.P. was sold, generating net cash proceeds of $104.3 million and a gain to Cheniere of $128.3 million.

(4)

Amount in 2010 relates to the cost to amend certain provisions of our 2008 Loans (described below under "Debt Agreements"). Amount in 2009 relates to gains on the termination of $120.4 million of our Convertible Senior Unsecured Notes. Amount in 2008 relates to losses on the termination of a $95.0 million bridge loan in August 2008. Amounts in 2006 primarily relate to losses on the termination of a Sabine Pass LNG credit facility and term loan in November 2006. See Note 15—“Long-Term Debt and Long-Term Debt—Related Parties” of our Notes to Consolidated Financial Statements.


(5)	Amounts in 2006 primarily relate to losses on the termination of hedge transactions related to the termination of a Sabine Pass LNG credit facility and term loan in November 2006.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATION

Introduction

The following discussion and analysis presents management’s view of our business, financial condition and overall performance and should be read in conjunction with our Consolidated Financial Statements and the accompanying notes in “Financial Statements and Supplementary Data.” This information is intended to provide investors with an understanding of our past performance, current financial condition and outlook for the future. Our discussion and analysis include the following subjects:


•	Overview of Business


•	Overview of Significant 2010 Events


•	Liquidity and Capital Resources


•	Contractual Obligations


•	Results of Operations


•	Off-Balance Sheet Arrangements


•	Inflation and Changing Prices


•	Summary of Critical Accounting Policies and Estimates


•	Recent Accounting Standards

Overview of Business

We own and operate the Sabine Pass LNG terminal in Louisiana through our 90.6% ownership interest in and management agreements with Cheniere Energy Partners, L.P. (“Cheniere Partners”) (NYSE Amex Equities: CQP), which is a publicly traded partnership we created in 2007. We also own and operate the Creole Trail Pipeline, which interconnects the Sabine Pass LNG terminal with markets in North America. One of our subsidiaries, Cheniere Marketing, LLC (“Cheniere Marketing”), is marketing LNG and natural gas on its own behalf and on behalf of Cheniere Partners, and is working to monetize LNG storage and regasification capacity reserved by Cheniere Partners at the Sabine Pass LNG terminal. Cheniere Partners is developing a liquefaction project to provide bi-directional LNG import and export service at the Sabine Pass LNG terminal. We are in various stages of developing other LNG terminal and pipeline related projects, each of which, among other things, will require acceptable commercial and financing arrangements before we make a final investment decision.

Overview of Significant 2010 Events

Our significant accomplishments during 2010 include the following:


•	In March 2010, Cheniere Marketing entered into various agreements (the “LNGCo Agreements”) with JPMorgan LNG Co. (“LNGCo”), an indirect subsidiary of JPMorgan Chase & Co., effective April 1, 2010, providing Cheniere Marketing with financial support to source more cargoes of LNG than it could source on a stand-alone basis;


•	In June 2010, we used $102.0 million of cash received from the sale of our 30% interest in Freeport LNG Development, L.P. to repay a portion of our 2007 Term Loan described below;


•	In June 2010, Cheniere Partners initiated a project to add liquefaction services at the Sabine Pass LNG terminal that would transform the terminal into a bi-directional facility capable of liquefying natural gas and exporting LNG in addition to importing and regasifying foreign-sourced LNG;

•

In June 2010, Cheniere Marketing assigned its Terminal Use Agreement ("TUA") with Sabine Pass LNG, L.P. ("Sabine Pass LNG") to Cheniere Investments, LLC ("Cheniere Investments"), a wholly owned subsidiary of Cheniere Partners, and as a result, we were able to use $63.6 million of cash and cash equivalents held in a TUA reserve account to repay a portion of the 2008 convertible term loans (hereafter referred to as the "2008 Loans");

•

In June 2010, Cheniere Marketing entered into the Variable Capacity Rights Agreement ("VCRA") with Cheniere Investments, effective July 1, 2010. Under the terms of the VCRA, Cheniere Marketing was contracted by Cheniere Investments to monetize the regasification capacity at the Sabine Pass LNG terminal on its behalf in exchange for compensation based upon the profitability of each transaction undertaken by Cheniere Marketing;

•

In September 2010, Sabine Pass Liquefaction, LLC ("Sabine Liquefaction"), a subsidiary of Cheniere Partners, received approval from the U.S. Department of Energy ("DOE") to export 16.0 mtpa of LNG produced from domestic natural gas for over thirty years starting not later than September 2020. This license authorizes Sabine Liquefaction to export LNG to purchasers in countries which have a Free Trade Agreement ("FTA") with the U.S. A second application was filed with the DOE requesting to expand the permit for a 20-year period and to allow export to countries with which the U.S. does not have an FTA;


•	In November and December of 2010, Sabine Liquefaction signed memoranda of understanding with a number of potential customers for bi-directional service at the Sabine Pass LNG terminal; and

•

In December 2010, the 2008 Loans were amended to eliminate the Lenders' Put Rights, as described herein, allow for the early prepayment of the 2008 Loans, allow us to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans with the proceeds, release restrictions on prepayments of other indebtedness at Cheniere as certain conditions are met, and terminate the lenders' right to nominate or designate board members of Cheniere and Cheniere Partners. In addition, 96.6% of the lenders agreed to terminate their rights to convert the Loans into Series B Preferred Stock of Cheniere and received 10.1 million shares of Cheniere common stock.

Liquidity and Capital Resources

Although consolidated for financial reporting, Cheniere, Sabine Pass LNG and Cheniere Partners operate with independent capital structures. We expect the cash needs for Sabine Pass LNG will be met through operating cash flows and existing unrestricted cash. We expect the cash needs for Cheniere Partners will be met through operating cash flows from Sabine Pass LNG, existing unrestricted cash and the issuance of Cheniere Partners common units. We expect the cash needs of Cheniere will be met by utilizing existing unrestricted cash, management fees from Sabine Pass LNG and Cheniere Partners, distributions from our investment in Cheniere Partners and operating cash flows from our pipeline and LNG and natural gas marketing businesses.

The following table presents (in thousands) Cheniere's restricted and unrestricted cash and cash equivalents for each portion of our capital structure as of December 31, 2010. All restricted and unrestricted cash and cash equivalents held by Cheniere Partners and Sabine Pass LNG are restricted by Cheniere as to usage or withdrawal:


	Sabine Pass LNG, L.P.		Cheniere Energy Partners, L.P.		Other Cheniere Energy, Inc.		Consolidated Cheniere Energy, Inc.
Cash and cash equivalents	$	—	$	—	$	74,161	$	74,161
Restricted cash and cash equivalents	102,052		47,423		6,479		155,954
Total	$	102,052	$	47,423	$	80,640	$	230,115

As of December 31, 2010, we had unrestricted cash and cash equivalents, accounts receivable and other working capital from LNG and natural gas marketing activities of approximately $85 million that will be available to Cheniere, which excludes cash and cash equivalents available to Cheniere Partners and Sabine Pass LNG. In addition, we had restricted cash and cash equivalents of $156.0 million, which were designated for the following purposes: $96.1 million for interest payments related to the Senior Notes described below; $6.0 million for Sabine Pass LNG's working capital; $47.4 million for Cheniere Partners' working capital; and $6.5 million for other restricted purposes.

In 2010, we accomplished the following items which we believe improved our liquidity and strengthened our capital structure:

•

In March 2010, our liquidity position was improved by entering into the LNGCo Agreements, which monetized our then-existing LNG inventory of 2,415,000 MMBtu, and which may reduce our working capital requirements to operate our marketing business by allowing us to source more cargoes of LNG than we could source on a stand-alone basis, and may provide additional financial support to monetize Cheniere Investments' capacity at the Sabine Pass LNG terminal and Creole Trail Pipeline;

•

In May 2010, our indebtedness was reduced by the pre-payment of $102.0 million of principal of the 2007 Term Loan as a result of the sale of our 30% limited partner interest in Freeport LNG. The principal pre-payment also reduced the amount of annual interest payable under the 2007 Term Loan by $10.1 million, offsetting or potentially exceeding any Freeport LNG distributions we might not have received as a result of having sold our 30% limited partner interest in Freeport LNG as a source of liquidity;

•

In June 2010, our liquidity and capital structure were improved by assigning Cheniere Marketing's TUA to a subsidiary of Cheniere Partners and entering into related transactions. We used the restricted cash that was previously reserved to fund Cheniere Marketing's TUA payment obligations to prepay $60.9 million in accrued interest and $2.7 million of principal on the 2008 Loans. As a result of the TUA assignment and related transactions, we increased our annual cash flow by $5 million to $16 million; and

•

We believe that Cheniere (excluding the sources and uses of capital by Sabine Pass LNG and Cheniere Partners) will have sufficient cash, other working capital and cash generated from its operations to fund its operating expenses and other cash requirements until at least the earliest date when principal payments may be required on its existing indebtedness, which will be in May 2012 (the maturity date of the 2007 Term Loan). Before that date, Cheniere expects to continue to restructure our finances and improve our capital structure, which will be accomplished by entering into long-term agreements, refinancing our existing indebtedness, issuing equity or other securities, selling assets, or a combination of the foregoing.

LNG Terminal Business

Cheniere Partners

Our ownership interest in the Sabine Pass LNG terminal is held through Cheniere Partners. We own approximately 90.6% of Cheniere Partners in the form of 10,891,357 common units, 135,383,831 subordinated units and a 2% general partner interest. Cheniere Partners owns a 100% interest in Sabine Pass LNG, which is operating the Sabine Pass LNG terminal.

We receive quarterly equity distributions from Cheniere Partners, and we receive management fees for managing Sabine Pass LNG and Cheniere Partners. For the year ended December 31, 2010, we received $18.5 million in distributions on our common units, $115.1 million in distributions on our subordinated units and $3.3 million in distributions on our general partnership interest. We also received fees of $8.0 million under our management agreements with Cheniere Partners and fees of $7.9 million under our management agreements with Sabine Pass LNG during the year ended December 31, 2010.

The common unit and general partner distributions are being funded from cash flows generated by Sabine Pass LNG's third-party TUA customers. The subordinated unit distributions we received in 2010 were funded from cash flows generated by Sabine Pass LNG's TUA with Cheniere Marketing. As a result of Cheniere Marketing's assignment of its TUA to Cheniere Investments, we have not received distributions on our subordinated units since the distribution made with respect to the quarter ended March 31, 2010.

During the subordination period, the common units have the right to receive distributions of available cash from operating surplus in an amount equal to the initial quarterly distributions of $0.425 per quarter, plus any arrearages in the payment of the initial quarterly distribution on the common units from prior quarters, before any distributions of available cash from operating surplus may be made on the subordinated units that we own. We expect that additional cash flows generated by future business development by subsidiaries of Cheniere Partners would be used to make quarterly distributions on our subordinated units before any increase in distributions to the common unitholders and general partner.

We and Cheniere Partners amended, effective as of July 1, 2010, the fee structure for the various general and administrative services provided by us for Cheniere Partners' benefit and changed it from a fixed fee to a variable fee. The amended and restated services agreement provides that fees will be paid quarterly from Cheniere Partners' unrestricted cash and cash equivalents remaining after making distributions to the common unitholders and the general partner in respect of each quarter and retaining certain reserves. Our ability to receive management fees from Cheniere Partners is dependent on our ability to, among other things,

manage Cheniere Partners' and Sabine Pass LNG's operating and administrative expenses, monetize the 2.0 Bcf/d regasification capacity under the Cheniere Investments TUA (as discussed below) and develop new projects through either internal development or acquisition to increase cash flow. The fixed management fees payable by Sabine Pass LNG remain unchanged.

In June 2010, Cheniere Marketing assigned its TUA with Sabine Pass LNG for 2.0 Bcf/d of regasification capacity at the Sabine Pass LNG terminal to Cheniere Investments, effective July 1, 2010. Concurrently, Cheniere Marketing was contracted by Cheniere Investments to monetize the LNG storage and regasification capacity at the Sabine Pass LNG terminal on its behalf in exchange for compensation based upon the profitability of each transaction undertaken by Cheniere Marketing.

The following diagram depicts our abridged organizational structure after the TUA assignment:

Pursuant to Cheniere Marketing's assignment of its TUA to Cheniere Investments, Cheniere Marketing will no longer make the approximately $250 million per year of payments to Sabine Pass LNG, and Cheniere Partners will not make distributions on our subordinated units unless it generates additional cash flow for Sabine Pass LNG's excess capacity or new business. Therefore, distributions to us on our subordinated units and conversion of the subordinated units into common units will depend upon the future business development of Cheniere Partners.

Concurrently with the TUA assignment, Cheniere Investments entered into the VCRA with Cheniere Marketing. Under the terms of the VCRA, Cheniere Marketing will be responsible for monetizing Cheniere Investments' TUA capacity at the Sabine Pass LNG terminal and is obligated to pay Cheniere Investments 80% of the expected gross margin of each cargo of LNG it arranges for delivery to the Sabine Pass LNG terminal. To the extent payments from Cheniere Marketing to Cheniere Investments under the VCRA or new Cheniere Partners' business increase Cheniere Partners' available cash in excess of the common unit and general partner distributions and certain reserves, the cash would be distributed to us in the form of distributions on our subordinated units and related general partner distributions. During the term of the VCRA, Cheniere Marketing is responsible for the payment of taxes and new regulatory costs under the TUA. Cheniere has guaranteed all of Cheniere Marketing's payment obligations under the VCRA.

In January 2011, Cheniere Partners initiated an at-the-market program to sell up to 1.0 million common units the proceeds from which would be used primarily to fund development costs associated with the liquefaction project.

Sabine Pass LNG terminal


•	Total Gas and Power North America, Inc. (“Total”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced April 1, 2009. Total, S.A. has guaranteed Total’s obligations under its TUA up to $2.5 billion, subject to certain exceptions; and


•	Chevron U.S.A., Inc. (“Chevron”) has reserved approximately 1.0 Bcf/d of regasification capacity and is obligated to make monthly capacity payments to Sabine Pass LNG aggregating approximately $125 million per year for 20 years that commenced July 1, 2009. Chevron Corporation has guaranteed Chevron’s obligations under its TUA up to 80% of the fees payable by Chevron.

Under each of these TUAs, Sabine Pass LNG is entitled to retain 2% of the LNG delivered for the customer's account.

Liquefaction Project

Other LNG terminals

As discussed above, in May 2010, we sold our 30% limited partnership interest in Freeport LNG. However, prior to the sale, Freeport LNG made aggregate distributions to us of $24.0 million since inception.

We will contemplate making final investment decisions to construct our Corpus Christi and Creole Trail LNG terminal projects upon, among other things, entering into acceptable commercial and financing arrangements for the applicable project. We do not expect to spend significant funds on these projects in the near-term.

Natural Gas Pipeline Business

The Creole Trail Pipeline, consisting of 94 miles of natural gas pipeline, is currently in-service and operating. We will contemplate making a final investment decision to construct the remaining 59 miles of the Creole Trail Pipeline, the Corpus Christi Pipeline, the Cheniere Southern Trail Pipeline and the Burgos Hub Project upon, among other things, receiving all required authorizations to construct and operate the applicable pipeline (and storage facility in the case of the Burgos Hub Project), to the extent not already obtained, and entering into acceptable commercial and financing arrangements for the applicable project. We do not expect to spend significant funds on these projects in the near-term.

LNG and Natural Gas Marketing Business

The accounting treatment for LNG inventory differs from the treatment for derivative positions such that the economics of Cheniere Marketing's activities are not transparent in the consolidated financial statements until all LNG inventory is sold and all

derivative positions are settled. Our LNG inventory is recorded as an asset at cost and is subject to lower of cost or market (“LCM”) adjustments at the end of each reporting period. The LCM adjustment market price is based on period-end natural gas spot prices, and any gain or loss from an LCM adjustment is recorded in our earnings at the end of each period. Revenue and cost of goods sold are not recognized in our earnings until the LNG is sold. Generally, our unrealized derivatives positions at the end of each period extend into the future to hedge the cash flow from future sales of our LNG inventory or to take market positions and hedge exposure associated with LNG and natural gas. These positions are measured at fair value, and we record the gains and losses from the change in their fair value currently in earnings. Thus, earnings from changes in the fair value of our derivatives may not be offset by losses from LCM adjustments to our LNG inventory because the LCM adjustments that may be made to LNG inventory are based on period-end spot prices that are different from the time periods of the prices used to fair value our derivatives. Any losses from changes in the fair value of our derivatives will not be offset by gains until the LNG is actually sold.

Management evaluates the performance of its LNG and natural gas marketing business activities differently than the measure calculated and presented in accordance with GAAP in our Consolidated Statement of Operations. Management calculates an adjusted LNG and natural gas revenue non-GAAP measure to assess the performance of the LNG and natural gas marketing business activities during each period. Management believes that the presentation of the adjusted LNG and natural gas revenue non-GAAP measure provides a meaningful indicator of the performance of our LNG and natural gas marketing business activities during the stated period.

The table below shows the differences between the components of both the LNG and natural gas marketing revenue GAAP measure (presented in our Consolidated Statement of Operations) and the adjusted LNG and natural gas revenue non-GAAP measure (in thousands):


	For the Year Ended December 31, 2010
	LNG and natural gas marketing revenue (GAAP measure)			Adjusted LNG and natural gas marketing revenue (Non-GAAP measure)			Difference
Physical LNG and natural gas sales	$	36,485		$	36,485		$	—
Cost of LNG	(29,761		)	(41,261		)	11,500		(1	)
Realized natural gas derivative gain	2,265			2,265			—
Other energy trading activities	10,033			10,033			—
LNG and natural gas revenue	$	19,022		$	7,522		$	11,500

(1)

The cost of LNG presented under GAAP only takes into consideration the cost of LNG that was sold during 2010, using the weighted average cost method for LNG inventory. The cost of LNG presented under non-GAAP measure represents the value of its LNG inventory based on published forward natural gas price curve prices corresponding to the future months when the LNG was planned to be sold as of December 31, 2009.

Under the GAAP measure, our LNG and natural gas marketing revenue was $19.0 million in 2010, but only $7.5 million was generated by marketing activities during the period. Therefore, we believe that the adjusted LNG and natural gas marketing revenue non-GAAP measure is a meaningful indicator of performance of our LNG and natural gas marketing business activities during a stated period.

LNGCo Agreements

In March 2010, Cheniere Marketing entered into the LNGCo Agreements with LNGCo, effective April 1, 2010, under which Cheniere Marketing has agreed to develop and maintain commercial and trading opportunities in the LNG industry and present any such opportunities exclusively to LNGCo. Cheniere Marketing also agreed to provide, or arrange for the provision of, all of the operations and administrative services required by LNGCo in connection with any LNG cargoes purchased by LNGCo, including negotiating agreements and arranging for transporting, receiving, storing, hedging and regasifying LNG cargoes. Cheniere Marketing does not have the authority to contractually bind LNGCo under the LNGCo Agreements. In the event LNGCo declines to purchase an LNG cargo presented to it by Cheniere Marketing under the LNGCo Agreements, Cheniere Marketing may pursue the opportunity on its own behalf or present it to third parties. The term of the LNGCo Agreements is two years; however, either party may terminate without penalty at the end of one year. In return for the services to be provided by Cheniere Marketing, LNGCo will pay a fixed fee to Cheniere Marketing and may pay additional fees depending upon the gross margins of each transaction and the aggregate gross margin earned during the term of the LNGCo Agreements.

During 2010, we recognized $10.1 million of marketing and trading revenues from LNGCo. As of December 31, 2010, Cheniere Marketing's maximum exposure relating to LNGCo was $5.2 million related to margin deposits that have been paid to LNGCo and fixed fee and gross margin revenue receivables earned as of December 31, 2010. A portion of this $5.2 million represents our fixed fee receivable and is reported as accounts and interest receivable, and the remaining portion is reported as other non-current assets and is to be paid to Cheniere Marketing upon the completion or termination of the LNGCo Agreements.

Corporate and Other Activities

We are required to maintain corporate general and administrative functions to serve our business activities described above. We believe that we have sufficient cash, other working capital and cash generated from our operations to fund our operating expenses and other cash requirements until at least the earliest date when principal payments on our outstanding indebtedness may be required. The earliest date that principal payments will be required is May 31, 2012, the maturity date of the 2007 Term Loan.

Sources and Uses of Cash

The following table summarizes (in thousands) the sources and uses of our cash and cash equivalents for the years ended December 31, 2010, 2009 and 2008. The table presents capital expenditures on a cash basis; therefore, these amounts differ from the amounts of capital expenditures, including accruals, that are referred to elsewhere in this report. Additional discussion of these items follows the table.


	Year Ended December 31,
	2010			2009			2008
Sources of cash and cash equivalents
Use of restricted cash and cash equivalents	$	34,423		$	241,101		$	465,323
Distribution from limited partnership investment in Freeport LNG	3,900			15,300			—
Proceeds from sale of limited partnership investment in Freeport LNG	104,330			—			—
Proceeds from debt issuance	—			—			239,965
Proceeds from debt issuance—related parties	—			—			250,000
Use of restricted U.S. Treasury securities	—			—			16,702
Other	104			—			472
Total sources of cash and cash equivalents	142,757			256,401			972,462

Uses of cash and cash equivalents
LNG terminal and pipeline construction-in-process, net	(4,223		)	(112,317		)	(583,871		)
Operating cash flow	(16,920		)	(97,857		)	(142,145		)
Repayments/repurchases of debt	(104,681		)	(30,030		)	(95,000		)
Distributions to non-controlling interest	(26,393		)	(26,392		)	(26,393		)
Purchase of treasury shares	(2,844		)	(999		)	(4,902		)
Debt issuance costs	(9		)	(121		)	(34,504		)
Investment in restricted cash and cash equivalents	—			—			(248,767		)
Advances under long-term contracts, net of transfers to construction-in-process	—			—			(14,032		)
Purchases of LNG for commissioning, net of amounts transferred to LNG terminal construction-in-process	—			—			(9,923		)
Other	(1,898		)	(2,505		)	(7,263		)
Total uses of cash and cash equivalents	(156,968		)	(270,221		)	(1,166,800		)

Net decrease in cash and cash equivalents	(14,211		)	(13,820		)	(194,338		)
Cash and cash equivalents—beginning of year	88,372			102,192			296,530
Cash and cash equivalents—end of year	$	74,161		$	88,372		$	102,192

Use of restricted cash and cash equivalents

In 2010, the $34.4 million of restricted cash and cash equivalents was used primarily to make distributions of $26.4 million to non-controlling interests, pay for construction activities at the Sabine Pass LNG terminal of $4.2 million and other individually immaterial items of $3.8 million.

In 2009, the $241.1 million of restricted cash and cash equivalents was used primarily to pay for construction activities at the Sabine Pass LNG terminal of $112.3 million, and to make distributions of $26.4 million to non-controlling interest. In addition, in June 2009, through an amendment of the 2008 Loans, we moved $65.2 million out of the TUA reserve account into an unrestricted cash and cash equivalents account.

In 2008, $465.3 million of restricted cash and cash equivalents was used to pay for construction activities at the Sabine Pass LNG terminal.

The decreased use of restricted cash and cash equivalents during 2010 primarily resulted from substantially completing construction of the Sabine Pass LNG terminal during the third quarter of 2009, and the decreased use in 2009 primarily resulted from completing construction of the initial sendout capacity of approximately 2.6 Bcf/d and storage capacity of approximately 10.1 Bcf at the Sabine Pass LNG terminal in September 2008.

Distribution from limited partnership investment in Freeport LNG

In 2010 and 2009, we received $3.9 million and $15.3 million of distributions from Freeport LNG, respectively. In May 2010, we sold our investment in Freeport LNG and, therefore, will not receive distributions in the future.

Proceeds from sale of limited partnership investment in Freeport LNG

We sold our 30% limited partner interest in Freeport LNG to institutional investors for net proceeds of $104.3 million and used $102.0 million of the proceeds to prepay principal of the 2007 Term Loan in June 2010.

Proceeds from debt issuance and proceeds from debt issuance—related parties

During 2008, we received $95.0 million from borrowings under the $95.0 million bridge loan (that was subsequently repaid), $250.0 million from borrowings under the 2008 Loans (considered related party), and $145.0 million, net of discount, from the additional issuance of the 2016 Notes (a portion of which is considered related party borrowings).

Use of restricted U.S. Treasury securities

In connection with the initial public offering of Cheniere Partners in 2007, Cheniere Partners received $98.4 million in net proceeds to purchase U.S. Treasury securities to fund a distribution reserve for the payments of initial quarterly distributions until Cheniere Partners was able to sustain funding of distributions to its unitholders from unrestricted cash. In 2008, $16.7 million of U.S. Treasury securities were used to fund the distribution reserve.

LNG terminal and pipeline construction-in-process, net

Capital expenditures for our LNG terminals and pipeline projects were $4.2 million, $112.3 million and $583.9 million in 2010, 2009 and 2008, respectively. Our capital expenditures decreased in 2010 and 2009 as a result of the substantial completion of the construction of the Sabine Pass LNG terminal in September 2009. Our capital expenditures decreased in 2008 as a result of the winding down and completion of the construction of the initial phases of the Sabine Pass LNG terminal and the Creole Trail Pipeline.

Operating cash flow

Net cash used in operations was $16.9 million, $97.9 million and $142.1 million in 2010, 2009 and 2008, respectively. Net cash used in operations related primarily to the general administrative overhead costs, pipeline operations costs, LNG and natural gas marketing overhead; offset by earnings from our LNG and natural gas marketing business. The decreases in 2010 and 2009 are primarily the result of Sabine Pass LNG beginning to receive capacity reservation fee payments from Total and Chevron during 2009.

Repayment/repurchases of debt

In 2010, 2009 and 2008, we used $104.7 million, $30.0 million and $95.0 million, respectively, of cash and cash equivalents to repay/repurchase a portion of our long-term debt.

In the second quarter of 2010, we used $102.0 million of the net proceeds from the sale of our limited partner interest in Freeport LNG to partially prepay the 2007 Term Loan. In addition, as a result of the assignment of the Cheniere Marketing TUA in the second quarter of 2010, we used $2.7 million to partially prepay the 2008 Loans. In the second quarter of 2009, we used a combination of $30.0 million cash and cash equivalents and 4.0 million common shares to prepay $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes. In 2008, we repaid borrowings under the $95.0 million bridge loan with a portion of the proceeds obtained from the 2008 Loans.

Distributions to non-controlling interest

During 2010, 2009 and 2008, Cheniere Partners distributed $26.4 million to its non-affiliated common unitholders.

Purchase of treasury shares

During 2010, 2009 and 2008, we used $2.8 million, $1.0 million and $4.9 million, respectively, of cash and cash equivalents to purchase restricted stock that was returned to us by employees to cover taxes related to their restricted stock that vested during the periods.

Debt issuance costs

The $34.5 million of debt issuance costs in 2008 related to the additional issuance of 2016 Notes (described below), the 2008 Loans and the $95.0 million bridge loan (which was subsequently repaid).

Investment in restricted cash and cash equivalents

Investments in restricted cash and cash equivalents are cash and cash equivalents that have been legally restricted to be used for a specific purpose. During 2008, we received $250.0 million from borrowings under the 2008 Loans and $145.0 million, net of discount, from the additional issuance of the 2016 Notes. Proceeds received from these borrowings were used to fund reserve accounts of $248.8 million, which we classified as restricted cash and cash equivalents.

Advances under long-term contracts, net of transfers to construction-in-process

We have entered into certain contracts and purchase agreements related to the construction of the Sabine Pass LNG terminal that require us to make payments to fund costs that will be incurred or equipment that will be received in the future. Advances made under long-term contracts on purchase commitments are carried at face value and transferred to property, plant, and equipment as the costs are incurred or equipment is received. The zero advances under long-term contracts in 2010 and 2009 resulted from substantial completion of the construction of the Sabine Pass LNG terminal in September 2009. During 2009, the Sabine Pass LNG terminal received equipment that it had previously advanced payment for under long-term contracts.

Debt Agreements

The following table (in thousands) and the explanatory paragraphs following the table summarize our various debt agreements as of December 31, 2010:


	Sabine Pass LNG, L.P.			Cheniere Energy Partners, L.P.		Other Cheniere Energy, Inc.			Consolidated Cheniere Energy, Inc.
Long-term debt (including related parties)
Senior Notes	$	2,215,500		$	—	$	—		$	2,215,500
2007 Term Loan	—			—		298,000			298,000
2008 Loans (including related parties)	—			—		262,657			262,657
Convertible Senior Unsecured Notes	—			—		204,630			204,630
Total long-term debt	2,215,500			—		765,287			2,980,787
Debt discount (including related parties)
Senior Notes (1)	(27,777		)	—		—			(27,777		)
Convertible Senior Unsecured Notes (2)	—			—		(25,501		)	(25,501		)
Total debt discount	(27,777		)	—		(25,501		)	(53,278		)
Long-term debt (including related parties), net of discount	$	2,187,723		$	—	$	739,786		$	2,927,509


(1)	In September 2008, Sabine Pass LNG issued an additional $183.5 million, par value, of 2016 Notes. The net proceeds from the additional issuance of the 2016 Notes were $145.0 million. The difference between the par value and the net proceeds is the debt discount, which will be amortized through the maturity of the 2016 Notes.


(2)	Effective as of January 1, 2009, we are required to record a debt discount on our Convertible Senior Unsecured Notes. The unamortized discount will be amortized through the maturity of the Convertible Senior Unsecured Notes.

Convertible Senior Unsecured Notes

In July 2005, we consummated a private offering of $325.0 million aggregate principal amount of Convertible Senior Unsecured Notes to qualified institutional buyers pursuant to Rule 144A under the Securities Act. The notes bear interest at a rate of 2¼% per year. Interest on the notes is payable semi-annually in arrears on February 1 and August 1 of each year. The notes are convertible at any time into our common stock under certain circumstances at an initial conversion rate of 28.2326 per $1,000 principal amount of the notes, which is equal to a conversion price of approximately $35.42 per share. As of December 31, 2010, no holders had elected to convert their notes. We may redeem some or all of the notes on or before August 1, 2012, for cash equal to 100% of the principal plus any accrued and unpaid interest if in the previous 10 trading days the volume-weighted average price of our common stock exceeds $53.13, subject to adjustment, for at least five consecutive trading days. In the event of such redemption, we will make an additional payment equal to the present value of all remaining scheduled interest payments through August 1, 2012, discounted at the U.S. Treasury securities rate plus 50 basis points. The indenture governing the notes contains customary reporting requirements.

As discussed in Note 15—“Long-Term Debt and Long-Term Debt—Related Parties” of our Notes to Consolidated Financial Statements, we adopted on January 1, 2009 an accounting standard that requires issuers of certain convertible debt instruments to separately account for the liability component and the equity component represented by the embedded conversion option in a manner that will reflect that entity's nonconvertible debt borrowing rate when interest costs are recognized in subsequent periods. The fair value of the embedded conversion option at the date of issuance of the Convertible Senior Unsecured Notes was determined to be $134.0 million and has been recorded as a debt discount to the Convertible Senior Unsecured Notes, with a corresponding adjustment to additional paid-in capital. At December 31, 2010, the unamortized debt discount to the Convertible Senior Unsecured Notes was $25.5 million.

During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million shares of common stock, reducing our principal amount due in 2012 to $204.6 million as of December 31, 2010 and 2009. As a result of the exchange, we recognized a gain of $45.4 million that we have reported as gain on early extinguishment of debt in our Consolidated Statements of Operations for the year ended December 31, 2009. The remaining principal amount of the Convertible Senior Unsecured Notes are convertible into 5.8 million of our common shares.

Sabine Pass LNG Senior Notes

Sabine Pass LNG has issued an aggregate principal amount of $2,215.5 million of Senior Notes ("Senior Notes") consisting of $550.0 million of 7¼% Senior Secured Notes due 2013 (the "2013 Notes") and $1,665.5 million of 7½% Senior Secured Notes due 2016 (the "2016 Notes"). Interest on the Senior Notes is payable semi-annually in arrears on May 30 and November 30 of each year. The Senior Notes are secured on a first-priority basis by a security interest in all of Sabine Pass LNG's equity interests and substantially all of its operating assets. Under the Sabine Pass Indenture governing the Senior Notes, except for permitted tax distributions, Sabine Pass LNG may not make distributions until certain conditions are satisfied: there must be on deposit in an interest payment account an amount equal to one-sixth of the semi-annual interest payment multiplied by the number of elapsed months since the last semi-annual interest payment, and there must be on deposit in a permanent debt service reserve fund an amount equal to one semi-annual interest payment of $82.4 million. Distributions are permitted only after satisfying the foregoing funding requirements, a fixed charge coverage ratio test of 2:1 and other conditions specified in the Sabine Pass Indenture.

As of December 31, 2010 and 2009, we classified zero and $72.9 million, respectively, as part of long-term debt-related parties on our Consolidated Balance Sheets because related parties held these portions of the Senior Notes. See Note 15—"Long-Term Debt and Long-Term Debt—Related Parties” of our Notes to Consolidated Financial Statements for additional information regarding our related party debt.

2007 Term Loan

In May 2007, Cheniere Subsidiary Holdings, LLC, a wholly owned subsidiary of Cheniere, entered into a $400.0 million credit agreement (“2007 Term Loan”). Borrowings under the 2007 Term Loan generally bear interest at a fixed rate of 9¾% per annum. Interest is calculated on the unpaid principal amount of the 2007 Term Loan outstanding and is payable quarterly in arrears on March 31, June 30, September 30 and December 31 of each year. The 2007 Term Loan will mature on May 31, 2012. The 2007 Term Loan is secured by a pledge of our 135,383,831 subordinated units in Cheniere Partners.

In May 2010, we sold our 30% interest in Freeport LNG to institutional investors for net proceeds of $104.3 million. The net proceeds from the sale were used to prepay $102.0 million of the 2007 Term Loan in May 2010. As of December 31, 2010 and 2009, $298.0 million and $400.0 million, respectively, were outstanding under the 2007 Term Loan and were included in long-term debt on our Consolidated Balance Sheet.

2008 Loans

In August 2008, we entered into a credit agreement pursuant to which we obtained $250.0 million in convertible term loans (“2008 Loans”). The 2008 Loans have a maturity date in 2018, but the lenders were initially able to require prepayment of the loans for 30 days following August 15, 2011, 2013 and 2015 (the "Lenders' Put Rights"), and upon a change of control. The 2008 Loans bear interest at a fixed rate of 12% per annum, except during the occurrence of an event of default during which time the rate of interest will be 14% per annum. Interest is due semi-annually on the last business day of January and July. At our option, until August 15, 2011, accrued interest may be added to the principal on each semi-annual interest date. The aggregate amount of all accrued interest to August 15, 2011 will be payable upon the maturity date. The 2008 Loans are secured by Cheniere's rights and fees payable under management services agreements with Sabine Pass LNG and Cheniere Partners, by Cheniere's 10.9 million common units in Cheniere Partners, by the equity and assets of Cheniere's pipeline entities, by the equity of various other subsidiaries and certain other assets and subsidiary guarantees. The outstanding principal amount was initially exchangeable for Cheniere's newly-created Series B Convertible Preferred Stock, par value $0.0001 per share (“Series B Preferred Stock”), with voting rights limited to the equivalent of 10,125,000 shares of Cheniere common stock. The exchange ratio was one share of Series B Preferred Stock for each $5,000 of outstanding borrowings, subject to adjustment. The aggregate preferred stock was exchangeable into shares of Cheniere common stock at a price of $5.00 per share pursuant to a broadly syndicated offering. No portion of any accrued interest was eligible for conversion into Series B Preferred Stock. Additionally, as long as the 2008 Loans were exchangeable for shares of Series B Preferred Stock or shares of Series B Preferred Stock remained outstanding, the holders of a majority of the 2008 Loans and Series B Preferred Stock, acting together, had the right to nominate two individuals to the Company's Board of Directors, and together with the Board of Directors, a third nominee, who would be an independent director.

In June 2010, the 2008 Loans were amended to permit all funds on deposit in the TUA Reserve Account to be applied to the prepayment of the accrued interest on the loans outstanding under the 2008 Loans, with any remainder to be applied to the prepayment of the principal balance of such 2008 Loans. As a result, $63.6 million from the TUA Reserve Account was used to prepay $60.9 million of accrued interest and $2.7 million of principal of the 2008 Loans.

In December 2010, the 2008 Loans were amended to eliminate the Lenders' Put Rights, allow for the early prepayment of the Loans, allow Cheniere to sell its Cheniere Partners common units held as collateral and use the proceeds to prepay the 2008 Loans and release restrictions on prepayments of other indebtedness at Cheniere as certain conditions are met. In addition, 96.6% of the lenders agreed to terminate their rights to convert the 2008 Loans into Series B Preferred Stock (the"Non-Convertible Lenders"). In addition, all of the lenders have also agreed to terminate their right to nominate or designate board members of Cheniere and Cheniere Partners. As part of the December 2010 amendments to the 2008 Loans, Cheniere issued an aggregate of 10.1 million shares of Cheniere common stock to the Non-Convertible Lenders.

Scorpion Capital Partners, LP, the holder of the remaining 3.4% of the 2008 Loans, will continue to retain its right to convert into Series B Preferred Stock (as described above), representing approximately 1.7 million shares of Cheniere common stock as of December 31, 2010.

As of December 31, 2010 and 2009, we classified $8.9 million and $276.2 million, respectively, as part of Long-Term Debt—Related Parties on our Consolidated Balance Sheets because related parties then held these portions of this debt. See Note 15—"Long-Term Debt and Long-Term Debt—Related Parties” of our Notes to Consolidated Financial Statements for additional information regarding our related party debt.

Issuances of Common Stock

During 2010, zero shares of our common stock were issued pursuant to the exercise of stock options. During 2010, we issued 1.2 million shares of restricted stock to new and existing employees. We also issued 10.1 million shares of our common stock to the Non-Convertible Lenders in connection with the December 2010 amendment to the 2008 Loans.

During 2009, no shares of our common stock were issued pursuant to the exercise of stock options. During 2009, we issued 886 shares of non-vested restricted stock to new and existing employees. We also issued 4.0 million shares of our common stock as part of the consideration used to repurchase a portion of the Convertible Senior Unsecured Notes during the second quarter of 2009.

During 2010 and 2009, we raised zero from the exercise of stock options and the exchange or exercise of warrants.

Contractual Obligations

We are committed to make cash payments in the future pursuant to certain of our contracts. The following table summarizes certain contractual obligations in place as of December 31, 2010 (in thousands).


	Payments Due for Years Ended December 31,
	Total		2011		2012-2013		2014-2015		Thereafter
Long-term debt (excluding interest) (1)	$	2,980,787	$	—	$	1,052,630	$	—	$	1,928,157
Operating lease obligations (2)(3)	308,281		13,582		26,849		24,537		243,313
Construction and purchase obligations (4)	4,028		3,944		84		—		—
Other obligations (5)	16,493		3,340		5,793		4,907		2,453
Total	$	3,309,589	$	20,866	$	1,085,356	$	29,444	$	2,173,923

(1)

Based on the total debt balance, scheduled maturities and interest rates in effect at December 31, 2010, our cash payments for interest would be $198.4 million in 2011, $212.2 million in 2012, $195.3 million in 2013, $158.8 million in 2014, $158.8 million in 2015 and $224.5 million for the remaining years for a total of $1,148.0 million. See Note 15—“Long-Term Debt and Long-Term Debt—Related Parties” of our Notes to Consolidated Financial Statements.


(2)	A discussion of these obligations can be found at Note 6—“Leases” of our Notes to Consolidated Financial Statements.


(3)	Minimum lease payments have not been reduced by a minimum sublease rental of $88.9 million due in the future under non-cancelable subleases. A discussion of these sublease rental payments can be found at Note 6—“Leases” of our Notes to Consolidated Financial Statements.


(4)	A discussion of these obligations can be found at Note 20—“Commitments and Contingencies” of our Notes to Consolidated Financial Statements.


(5)	Includes obligations for cooperative endeavor agreements, LNG terminal security services, telecommunication services and software licensing.

In addition, in the ordinary course of business, we maintain letters of credit and have certain cash and cash equivalents restricted in support of certain performance obligations of our subsidiaries. Restricted cash and cash equivalents totaled approximately $156.0 million at December 31, 2010. For more information, see Note 5—“Restricted Cash and Cash Equivalents” of our Notes to Consolidated Financial Statements.

Results of Operations

Overall Operations

2010 vs. 2009

Our consolidated net loss was $76.2 million, or $1.37 per share (basic and diluted), in 2010 compared to a net loss of $161.5 million, or $3.13 per share (basic and diluted), in 2009. The decrease in the 2010 net loss was primarily due to a gain in 2010 on the sale of our 30% interest in Freeport LNG, increased LNG terminal revenues as a result of the Sabine Pass LNG terminal starting commercial operations during 2009 that was partially offset by a loss on the early extinguishment of our 2008 Loans, increased LNG terminal and pipeline development and operations and maintenance expense, and increased depreciation, depletion and amortization expense (“DD&A”).

A significant portion of our loss was attributable to the recognition of non-cash, share-based payments recognized in the consolidated financial statements based on fair value at the date of grant. As a result of our issuance of non-cash, share-based payments to employees, we recorded $17.9 million and $19.2 million of non-cash compensation expense in 2010 and 2009, respectively. In addition, we recognized one-time charges in 2010 of $128.3 million for a gain on sale of equity method investment and $50.3 million for a loss on early extinguishment of debt. In 2009, we recognized one-time charges of $45.4 million for a gain on early extinguishment of debt. Not including the impact of these one-time charges in 2010 and 2009 and the impact of non-cash expense in 2010 and 2009, our net loss would have been $136.3 million, or $2.44 net loss per common share (basic and diluted), and $187.7 million, or $3.64 net loss per common share (basic and diluted), in 2010 and 2009 respectively.

2009 vs. 2008

Our consolidated net loss was $161.5 million, or $3.13 per share (basic and diluted), in 2009 compared to a net loss of $373.0 million, or $7.87 per share (basic and diluted), in 2008. The decrease in the loss was primarily due to increased LNG terminal revenues as a result of the Sabine Pass LNG terminal starting commercial operations during 2009, decreased LNG terminal and pipeline development expense, decreased general and administrative expenses, decreased restructuring charges and the gain from early extinguishment of debt, which were partially offset by increased LNG terminal and pipeline operating expenses, increased DD&A, decreased interest income and increased interest expense, net.

In addition, we recognized one-time charges in 2009 of $45.4 million for a gain on early extinguishment of debt. In 2008, we recognized one-time charges of $78.7 million for restructuring charges and $10.7 million for loss on early extinguishment of debt. Not including the impact of these one-time charges in 2009 and 2008 and the impact of non-cash expense in 2009 and 2008, our net loss would have been $187.7 million, or $3.64 net loss per common share (basic and diluted), and $228.6 million, or $4.83 net loss per common share (basic and diluted), in 2010 and 2009 respectively.

LNG Terminal Revenue

2010 vs. 2009

LNG terminal revenue increased $99.4 million, from $170.1 million in 2009 to $269.5 million in 2010. Of this total increase, $96.9 million was a result of Total and Chevron capacity reservation fee TUA payments beginning on April 1, 2009 and July 1, 2009, respectively. The remaining increase in LNG terminal revenue is a result of increased revenues earned from our 2% retainage and LNG export cargo loading fees charged to customers in 2010.

2009 vs. 2008

LNG terminal revenue increased $170.1 million, from zero in 2008 to $170.1 million in 2009. As a result of the completion of the Sabine Pass LNG receiving terminal in 2009, the capacity reservation fee TUA payments began on April 1, 2009 and July 1, 2009 for Total and Chevron, respectively. In addition to the TUA capacity reservation fee, we recognized $9.3 million of other revenue primarily related to revenues earned from fees charged to customers using our tug boats associated with the Sabine Pass LNG receiving terminal.

LNG and Natural Gas Marketing Revenue

Operating results from marketing and trading activities are presented on a net basis on our Consolidated Statement of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation costs of LNG and subsequent sales of natural gas to third parties. Our marketing and trading revenues also include pretax derivative gains/losses and inventory lower-of-cost-or-market adjustments, if any. See the table below (in thousands) for an itemized comparison of each major type of energy trading and risk management activity:


	Years Ended December 31,
	2010		2009			2008
Physical LNG and natural gas sales, net of costs	$	6,724	$	2,296		$	943
Inventory lower-of-cost-or-market write-downs	—		(3,323		)	—
Gain (loss) from derivatives	2,265		8,606			(1,435		)
Other energy trading activities	10,033		508			3,406
Total LNG and natural gas marketing revenue	$	19,022	$	8,087		$	2,914

2010 vs. 2009

LNG and natural gas marketing revenues increased $10.9 million, from $8.1 million in 2009 to $19.0 million in 2010. The $8.1 million in 2009 primarily resulted from $8.6 million in derivative gains and $2.3 million of net revenue from physical sales of regasified LNG, which was offset by a $3.3 million inventory write-down. The $19.0 million in 2010 primarily resulted from fixed fee and gross margin revenue from LNGCo and physical sales of LNG.

2009 vs. 2008

LNG and natural gas marketing revenues increased $5.2 million, from $2.9 million in 2008 to $8.1 million in 2009. The $8.1 million in 2009 primarily resulted from $8.6 million in derivative gains and $2.3 million of net revenue from physical sales of regasified LNG, which was offset by a $3.3 million inventory write-down. The increase in natural gas marketing and trading revenue is primarily a result of the different marketing and trading activities we were engaged in during 2009 compared to 2008. Prior to the downsizing of our natural gas marketing business in April 2008, we had entered into various commercial transactions that were unwound, terminated or assigned in 2008 in connection with such downsizing. The $2.9 million gain in 2008 primarily resulted from revenue from short-term TUA option transactions. During 2009, we began purchasing, transporting and unloading commercial LNG cargoes into the Sabine Pass LNG terminal and used certain hedging strategies to maximize margins on these cargoes.

LNG Terminal and Pipeline Development Expense

Our LNG terminal and pipeline development expenses include primarily professional costs associated with front-end engineering and design work, obtaining regulatory approvals authorizing construction of our facilities and other required permitting for our planned LNG terminals and natural gas pipelines.

2010 vs. 2009

LNG terminal and pipeline development expenses increased $11.8 million in 2010 compared to 2009. The increase resulted from liquefaction development activities at the Sabine Pass LNG terminal in 2010. The 2009 costs primarily related to continued site maintenance costs incurred with respect to our potential Corpus Christi and Creole Trail LNG terminal projects.

2009 vs. 2008

LNG terminal and pipeline development expenses decreased $10.3 million in 2009 compared to 2008. The decrease resulted from less development activities at the Sabine Pass LNG terminal than in 2008. The 2009 costs primarily related to continued site maintenance costs incurred with respect to our proposed Corpus Christi and Creole Trail LNG terminal projects.

LNG Terminal and Pipeline Operating Expense

Our LNG terminal and pipeline operating expenses include costs incurred to operate the Sabine Pass LNG terminal and the Creole Trail Pipeline.

2010 vs. 2009

LNG terminal and pipeline operating expense increased $5.5 million, from $36.9 million in 2009 to $42.4 million in 2010. This $5.5 million increase primarily resulted from the achievement of full operability of the Sabine Pass LNG terminal, with approximately 4.0 Bcf/d of total sendout capacity and five LNG storage tanks with approximately 16.9 Bcf of aggregate storage capacity, in the third quarter of 2009.

2009 vs. 2008

LNG terminal and pipeline operating expense increased $22.4 million, from $14.5 million in 2008 to $36.9 million in 2009. This $22.4 million increase primarily resulted from the achievement of commercial operability of the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal in the third quarter of 2008 and the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 (as described above).

Depreciation, Depletion and Amortization (“DD&A”)

2010 vs. 2009

DD&A increased $9.1 million, from $54.2 million in 2009 to $63.3 million in 2010. This increase is primarily a result of the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 (as described above).

2009 vs. 2008

DD&A increased $29.9 million, from $24.3 million in 2008 to $54.2 million in 2009. This increase is primarily related to beginning deprecation on the costs associated with the initial 2.6 Bcf/d of sendout capacity and 10.1 Bcf of storage capacity of the Sabine Pass LNG terminal, which was placed into service in the third quarter of 2008. In addition, depreciation expense increased in 2009 as a result of the substantial completion of construction and achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009 (as described above).

General and Administrative Expense (“G&A Expense”)

Our G&A Expense includes costs that are incurred for general corporate purposes, LNG and natural gas marketing activities, the Sabine Pass LNG terminal and Creole Trail Pipeline activities.

2009 vs. 2008

The $56.8 million reduction in G&A Expense from 2008 to 2009 primarily resulted from a reduction in salaries and benefits incurred in 2009 associated with downsizing our natural gas marketing business activities and the allocation of salaries and benefits to operating costs as a result of the achievement of commercial operability of the Sabine Pass LNG terminal in September 2008.

Restructuring Charges

During 2009 and 2008, we incurred less than $0.1 million and $78.7 million of restructuring charges, respectively, resulting from our cost savings program in connection with downsizing our natural gas marketing business activities, nearing completion of significant construction activities for both the Sabine Pass LNG terminal and Creole Trail Pipeline and seeking alternative arrangements for our time charter interests in two LNG vessels.

Gain/(Loss) on Early Extinguishment of Debt

2010 vs. 2009

Gain/(Loss) on early extinguishment of debt decreased $95.7 million, from a $45.4 million gain in 2009 to a $50.3 million loss in 2010. During the fourth quarter of 2010, the 2008 Loans were amended to eliminate the Lenders' Put Rights, allow for the early prepayment of the 2008 Loans, allow us to sell Cheniere Partners common units held as collateral and prepay the 2008 Loans, release restrictions on prepayments of other indebtedness as certain conditions are met. In addition, the Non-Convertible Lenders agreed to terminate their rights to convert the 2008 Loans into Series B Preferred Stock. Also, all of the lenders agreed to terminate their right to nominate or designate board members of Cheniere and Cheniere Partners. As part of the amendments to the 2008 Loans, we issued 10.1 million shares of Cheniere common stock to the Non-Convertible Lenders. The value of the 10.1 million Cheniere common shares were expensed as a loss on early extinguishment of debt in the fourth quarter of 2010. During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million common shares, reducing our principal amount due in 2012 to $204.6 million. As a result of the exchange, we recognized a gain of $45.4 million that was reported as a gain on early extinguishment of debt in 2009.

2009 vs. 2008

Gain/(Loss) on early extinguishment of debt increased $56.1 million, from a $10.7 million loss in 2008 to a $45.4 million gain in 2009. During the second quarter of 2009, we reduced debt by exchanging $120.4 million aggregate principal amount of our Convertible Senior Unsecured Notes for a combination of $30.0 million cash and cash equivalents and 4.0 million common shares, reducing our principal amount due in 2012 to $204.6 million. As a result of the exchange, we recognized a gain of $45.4 million that was reported as a gain on early extinguishment of debt in 2009.

Interest Income

2009 vs. 2008

Interest income decreased $18.9 million in 2009 compared to 2008 because of the lower average invested cash balances resulting from the use of cash to pay construction costs and interest payments, as well as lower interest rates.

Interest Expense, net

2010 vs. 2009

Interest expense, net of amounts capitalized, increased $18.7 million, from $243.3 million in 2009 to $262.0 million in 2010. The increase in interest expense resulted from the achievement of full operability of the Sabine Pass LNG terminal in the third quarter of 2009, which reduced the amount of interest expense that was capitalized.

2009 vs. 2008

Interest expense, net of amounts capitalized, increased $96.2 million, from $147.1 million in 2008 to $243.3 million in 2009. The increase in interest expense was caused by additional debt issuances during the third quarter of 2008 and a decrease in capitalized interest as a result of placing in service the initial phase of the Sabine Pass LNG terminal and Creole Trail Pipeline in the third quarter of 2008 and second quarter of 2008, respectively.

Off-Balance Sheet Arrangements

As of December 31, 2010, we had no “off-balance sheet arrangements” that may have a current or future material affect on our consolidated financial position or results of operations.

Inflation and Changing Prices

During 2010, 2009 and 2008, inflation and changing commodity prices have had an impact on our oil and gas revenues but have not significantly impacted our results of operations.

Summary of Critical Accounting Policies and Estimates

The selection and application of accounting policies is an important process that has developed as our business activities have evolved and as the accounting rules have developed. Accounting rules generally do not involve a selection among alternatives but involve an implementation and interpretation of existing rules, and the use of judgment, to apply the accounting rules to the specific set of circumstances existing in our business. In preparing our consolidated financial statements in conformity with GAAP, we endeavor to comply properly with all applicable rules on or before their adoption, and we believe that the proper implementation and consistent application of the accounting rules are critical. However, not all situations are specifically addressed in the accounting literature. In these cases, we must use our best judgment to adopt a policy for accounting for these situations. We accomplish this by analogizing to similar situations and the accounting guidance governing them.

Accounting for LNG Activities

Generally, we begin capitalizing the costs of our LNG terminals and related pipelines once the individual project meets the following criteria: (i) regulatory approval has been received, (ii) financing for the project is available and (iii) management has committed to commence construction. Prior to meeting these criteria, most of the costs associated with a project are expensed as incurred. These costs primarily include professional fees associated with front-end engineering and design work, costs of securing necessary regulatory approvals, and other preliminary investigation and development activities related to our LNG terminals and related pipelines.

Generally, costs that are capitalized prior to a project meeting the criteria otherwise necessary for capitalization include: land and lease option costs that are capitalized as property, plant and equipment and certain permits that are capitalized as intangible LNG assets. The costs of lease options are amortized over the life of the lease once obtained. If no lease is obtained, the costs are expensed.

We capitalize interest and other related debt costs during the construction period of our LNG terminal. Upon commencement of operations, capitalized interest, as a component of the total cost, will be amortized over the estimated useful life of the asset.

Revenue Recognition

LNG regasification capacity reservation fees are recognized as revenue over the term of the respective TUAs. Advance capacity reservation fees are initially deferred and amortized over a 10-year period as a reduction of a customer’s regasification capacity reservation fees payable under its TUA. The retained 2% of LNG delivered for each customer’s account at the Sabine Pass LNG terminal is recognized as revenue as Sabine Pass LNG performs the services set forth in each customer’s TUA.

Use of Estimates

The preparation of consolidated financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make certain estimates and assumptions that affect the amounts reported in the consolidated financial statements and the accompanying notes. Actual results could differ from the estimates and assumptions used.

Estimates used in the assessment of impairment of our long-lived assets, including goodwill, are the most significant of our estimates. There are numerous uncertainties inherent in estimating future cash flows of assets or business segments. The accuracy of any cash flow estimate is a function of judgment used in determining the amount of cash flows generated. As a result, cash flows may be different from the cash flows that we use to assess impairment of our assets. Management reviews its estimates of cash flows on an ongoing basis using historical experience and other factors, including the current economic and commodity price environment. Significant negative industry or economic trends, including a significant decline in the market price of our common stock, reduced estimates of future cash flows for our business segments or disruptions to our business could lead to an impairment charge of our long-lived assets, including goodwill and other intangible assets. Our valuation methodology for assessing impairment requires management to make judgments and assumptions based on historical experience and to rely heavily on projections of future operating performance. Projections of future operating results and cash flows may vary significantly from results. In addition, if our analysis results in an impairment of our long-lived assets, including goodwill, we may be required to record a charge to earnings in our consolidated financial statements during a period in which such impairment is determined to exist, which may negatively impact our results of operations.

Other items subject to estimates and assumptions include asset retirement obligations, valuation allowances for net deferred tax assets, valuations of derivative instruments, valuations of non-cash compensation and collectability of accounts receivable and other assets.

As future events and their effects cannot be determined accurately, actual results could differ significantly from our estimates.

LNG and Natural Gas Marketing

We have determined that our LNG and natural gas marketing business activities are energy trading and risk management activities for trading purposes and have elected to present these activities on a net basis on our Consolidated Statement of Operations. Marketing and trading revenues represent the margin earned on the purchase and transportation of LNG purchases and subsequent sales of natural gas to third parties. These energy trading and risk management activities include, but are not limited to: purchase of LNG and natural gas, transportation contracts, and derivatives. Below is a brief description of our accounting treatment of each type of energy trading and risk management activity and how we account for it:

Purchase of LNG and natural gas

The purchase value of LNG or natural gas inventory is recorded as an asset on our Consolidated Balance Sheet at the cost to acquire the product. Our inventory is subject to LCM adjustment each quarter. Recoveries of losses resulting from interim period LCM adjustments are made due to market price recoveries on the same inventory in the same fiscal year and are recognized as gains in later interim periods with such gains not exceeding previously recognized losses. Any adjustment to our inventory is recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statement of Operations.

Transportation contracts

We enter into transportation contracts with respect to the transport of LNG or natural gas to a specific location for storage or sale. Transportation costs that are incurred during the purchase of LNG or natural gas are capitalized as part of the acquisition costs of the product. Transportation costs incurred to sell LNG or natural gas are recorded on a net basis as LNG and natural gas marketing revenue on our Consolidated Statement of Operations.

Derivatives

We use derivative instruments from time to time to hedge the cash flow variability of our commodity trading activities. We have disclosed certain information regarding these derivative positions, including the fair value of our derivative positions, in Note 16—“Financial Instruments” of our Notes to Consolidated Financial Statements. We record changes in the fair value of our derivative positions in our LNG and natural gas marketing revenue on our Consolidated Statement of Operations based on the value for which the derivative instrument could be exchanged between willing parties. To date, all of our derivative positions fair value determinations have been made by management using quoted prices in active markets for identical instruments. We had no open financial derivative instruments at December 31, 2010.

Regulated Natural Gas Pipelines

Our developing natural gas pipeline business is subject to the jurisdiction of the FERC in accordance with the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. The economic effects of regulation can result in a regulated company recording as assets those costs that have been or are expected to be approved for recovery from customers, or recording as liabilities those amounts that are expected to be required to be returned to customers, in a rate-setting process in a period different from the period in which the amounts would be recorded by an unregulated enterprise. Accordingly, we record assets and liabilities that result from the regulated rate-making process that may not be recorded under GAAP for non-regulated entities. We continually assess whether regulatory assets are probable of future recovery by considering factors such as applicable regulatory changes and recent rate orders applicable to other regulated entities. Based on this continual assessment, we believe the existing regulatory assets are probable of recovery. These regulatory assets and liabilities are primarily classified in the Consolidated Balance Sheets as Other Assets and Other Liabilities. We periodically evaluate their applicability under GAAP, and consider factors such as regulatory changes and the effect of competition. If cost-based regulation ends or competition increases, we may have to reduce our asset balances to reflect a market basis less than cost and write-off the associated regulatory assets and liabilities.

Items that may influence our assessment are:


•	inability to recover cost increases due to rate caps and rate case moratoriums;


•	inability to recover capitalized costs, including an adequate return on those costs through the rate-making process and the FERC proceedings;


•	excess capacity;


•	increased competition and discounting in the markets we serve; and


•	impacts of ongoing regulatory initiatives in the natural gas industry.

Natural gas pipeline costs include amounts capitalized as an Allowance for Funds Used During Construction (“AFUDC”).

The rates used in the calculation of AFUDC are determined in accordance with guidelines established by the FERC. AFUDC represents the cost of debt and equity funds used to finance our natural gas pipeline additions during construction. AFUDC is capitalized as a part of the cost of our natural gas pipelines. Under regulatory rate practices, we generally are permitted to recover AFUDC, and a fair return thereon, through our rate base after our natural gas pipelines are placed in service.

Cash Flow Hedges

We have used, and may in the future use, derivative instruments to limit our exposure to variability in expected future cash flows. Cash flow hedge transactions hedge the exposure to variability in expected future cash flows. In the case of cash flow hedges, the hedged item (the underlying risk) is generally unrecognized (i.e., not recorded on the consolidated balance sheet prior to settlement), and any changes in the fair value, therefore, will not be recorded within earnings. Conceptually, if a cash flow hedge is effective, this means that a variable, such as a movement in interest rates, has been effectively fixed so that any fluctuations will have no net result on either cash flows or earnings. Therefore, if the changes in fair value of the hedged item are not recorded in earnings, then the changes in fair value of the hedging instrument (the derivative) must also be excluded from the income statement or else a one-sided net impact on earnings will be reported, despite the fact that the establishment of the effective hedge results in no net economic impact. To prevent such a scenario from occurring, GAAP requires that the fair value of a derivative instrument designated as a cash flow hedge to be recorded as an asset or liability on the balance sheet, but with the offset reported as part of other comprehensive income, to the extent that the hedge is effective. We assess, both at the inception of each hedge and on an on-going basis, whether the derivatives that are used in our hedging transactions are highly effective in offsetting changes in cash flows of the hedged items. On an on-going basis, we monitor the actual dollar offset of the hedges’ market values compared to hypothetical cash flow hedges. Any ineffective portion of the cash flow hedges will be reflected in earnings. Ineffectiveness is the amount of gains or losses from derivative instruments that are not offset by corresponding and opposite gains or losses on the expected future transaction.

Goodwill

Goodwill represents the excess of cost over fair value of the assets of businesses acquired. It is evaluated annually for impairment by first comparing our management’s estimate of the fair value of a reporting unit with its carrying value, including goodwill. If the carrying value of the reporting unit exceeds its fair value, a computation of the implied fair value of the goodwill is compared with its related carrying value. If the carrying value of the reporting unit goodwill exceeds the implied fair value of that goodwill, an impairment loss is recognized in the amount of the excess. We had goodwill of approximately $76.8 million at December 31, 2010 and 2009, attributable to our LNG terminal segment.

We perform an annual goodwill impairment review in the fourth quarter of each year, although we may perform a goodwill impairment review more frequently whenever events or circumstances indicate that the carrying value may not be recoverable. As discussed above regarding our use of estimates, our judgments and assumptions are inherent in our management’s estimate of future cash flows used to determine the estimate of the reporting unit’s fair value. The use of alternate judgments and/or assumptions could result in the recognition of different levels of impairment charges in the consolidated financial statements.

Share-Based Compensation Expense

We recognize our share-based payments to employees in our Consolidated Financial Statements based on their fair values at the date of grant. The calculated fair value is recognized as expense (net of any capitalization) over the requisite service period, net of estimated forfeitures, using the straight-line method.

Determining the appropriate fair value model and calculating the fair value of share-based payment awards requires the use of highly subjective assumptions, including the expected life of the share-based payment awards and stock price volatility. We believe that implied volatility, calculated based on traded options of our common stock, combined with historical volatility is an appropriate indicator of expected volatility and future stock price trends. Therefore, the expected volatility for the year ended December 31, 2010 used in our fair value model was based on a combination of implied and historical volatilities. The assumptions used in calculating the fair value of share-based payment awards represent our best estimates, but these estimates involve inherent uncertainties and the application of management's judgment. As a result, if factors change and we use different assumptions, our share-based compensation expense could be materially different in the future. In addition, we are required to estimate the expected forfeiture rate and only recognize expense for those shares expected to vest. If our actual forfeiture rate is materially different from our estimate, future share-based compensation expense could be significantly different from what we have recorded in the current period (See Note 18—“Share-Based Compensation” of our Notes to Consolidated Financial Statements).

Recent Accounting Standards

In June 2009, the Financial Accounting Standards Board (“FASB”) issued an amendment to the accounting and disclosure requirements for the consolidation of variable interest entities. This guidance affects the overall consolidation analysis and requires enhanced disclosures on involvement with variable interest entities. The guidance is effective as of the first annual reporting period beginning after November 15, 2009, for interim periods within the first annual reporting period and thereafter. Our adoption of this authoritative guidance had no impact on our financial position, results of operations or cash flow.

In January 2010, the FASB issued authoritative guidance which requires additional disclosures and clarifies certain existing disclosure requirements regarding fair value measurements. This guidance is effective for interim and annual reporting periods beginning after December 15, 2009. We adopted this guidance effective January 1, 2010. However, none of the specific additional disclosure requirements were applicable to us at the time of filing this report. (See Note 16—“Financial Instruments” of our Notes to Consolidated Financial Statements for our fair value measurement disclosures).

In December 2010, the FASB issued an amendment to address diversity in practice in the application of goodwill impairment testing by entities with reporting units with zero or negative carrying amounts, eliminating an entity’s ability to assert that a reporting unit is not required to perform additional analysis because the carrying amount of the reporting unit is zero or negative despite the existence of qualitative factors that indicate the goodwill is more likely than not impaired. This amendment is effective for fiscal years and interim periods within those years beginning after December 15, 2010. We do not expect the adoption of this amendment to have a material impact on our financial position, results of operations and cash flow.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Cash Investments

We have cash investments that we manage based on internal investment guidelines that emphasize liquidity and preservation of capital. Such cash investments are stated at historical cost, which approximates fair market value on our Consolidated Balance Sheet.

Marketing and Trading Commodity Price Risk

Through Cheniere Marketing, from time to time we enter into natural gas and foreign currency derivatives to hedge the exposure of future cash flows associated with the LNG that we hold. We use value at risk (“VaR”) and other methodologies for market risk measurement and control purposes. The VaR is calculated using the Monte Carlo simulation method. At December 31, 2010 and 2009, the one-day VaR with a 95% confidence interval on our derivative positions was zero and less than $0.1 million, respectively.

We had not entered into any natural gas or foreign currency derivative positions as of December 31, 2010.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

CHENIERE ENERGY, INC. AND SUBSIDIARIES



Management’s Reports to the Stockholders of Cheniere Energy, Inc.	54
Reports of Independent Registered Public Accounting Firm—Ernst & Young LLP	55
Consolidated Balance Sheets	57
Consolidated Statements of Operations	58
Consolidated Statements of Stockholders’ (Deficit) Equity	59
Consolidated Statements of Cash Flows	60
Notes to Consolidated Financial Statements	61
Supplemental Information to Consolidated Financial Statements—Summarized Quarterly Financial Data	87

MANAGEMENT’S REPORTS TO THE STOCKHOLDERS OF CHENIERE ENERGY, INC.

Management’s Report on Internal Control Over Financial Reporting

As management, we are responsible for establishing and maintaining adequate internal control over financial reporting for Cheniere Energy, Inc. and its subsidiaries (“Cheniere”). In order to evaluate the effectiveness of internal control over financial reporting, as required by Section 404 of the Sarbanes-Oxley Act of 2002, we have conducted an assessment, including testing using the criteria in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Cheniere’s system of internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements and, even when determined to be effective, can only provide reasonable assurance with respect to financial statement preparation and presentation.

Based on our assessment, we have concluded that Cheniere maintained effective internal control over financial reporting as of December 31, 2010, based on criteria in Internal Control—Integrated Framework issued by the COSO.

Cheniere’s independent auditors, Ernst & Young LLP, have issued an audit report on Cheniere’s internal control over financial reporting.

Management’s Certifications

The certifications of Cheniere’s Chief Executive Officer and Chief Financial Officer required by the Sarbanes-Oxley Act of 2002 have been included as Exhibits 31 and 32 in Cheniere’s Form 10-K.

CHENIERE ENERGY, INC.



By:	/s/ CHARIF SOUKI	By:	/s/ MEG A. GENTLE
	Charif Souki Chief Executive Officer and President		Meg A. Gentle Senior Vice President and Chief Financial Officer

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Cheniere Energy, Inc.

We have audited the accompanying consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' (deficit) equity, and cash flows for each of the three years in the period ended December 31, 2010. Our audits also included the financial statement schedule listed in the Index at Item 15(a). These financial statements and schedule are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedule based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Cheniere Energy, Inc. and subsidiaries at December 31, 2010 and 2009, and the consolidated results of their operations and their cash flows for each of the three years in the period ended December 31, 2010, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedule, when considered in relation to the basic financial statements taken as a whole, presents fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Cheniere Energy, Inc.'s internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 2, 2011 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

March 2, 2011

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

The Board of Directors and Stockholders of

Cheniere Energy, Inc.

We have audited Cheniere Energy, Inc. and subsidiaries' internal control over financial reporting as of December 31, 2010, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (the COSO criteria). Cheniere Energy, Inc. and subsidiaries' management is responsible for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management's Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

In our opinion, Cheniere Energy, Inc. and subsidiaries maintained, in all material respects, effective internal control over financial reporting as of December 31, 2010, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated balance sheets of Cheniere Energy, Inc. and subsidiaries as of December 31, 2010 and 2009, and the related consolidated statements of operations, stockholders' (deficit) equity, and cash flows for each of the three years in the period ended December 31, 2010 and our report dated March 2, 2011 expressed an unqualified opinion thereon.

/s/ ERNST & YOUNG LLP

Ernst & Young LLP

Houston, Texas

March 2, 2011

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(in thousands, except share data)


	December 31,
	2010			2009
ASSETS
Current assets
Cash and cash equivalents	$	74,161		$	88,372
Restricted cash and cash equivalents	73,062			138,309
Accounts and interest receivable	4,699			9,899
LNG inventory	1,212			32,602
Prepaid expenses and other	12,476			17,093
Total current assets	165,610			286,275

Non-current restricted cash and cash equivalents	82,892			82,892
Property, plant and equipment, net	2,157,597			2,216,855
Debt issuance costs, net	41,656			47,043
Goodwill	76,819			76,819
Intangible LNG assets	6,067			6,088
Other	22,866			16,650
Total assets	$	2,553,507		$	2,732,622

LIABILITIES AND STOCKHOLDERS' DEFICIT
Current liabilities
Accounts payable	$	1,283		$	426
Accrued liabilities	38,459			38,425
Deferred revenues	26,592			26,456
Other	—			905
Total current liabilities	66,334			66,212

Long-term debt, net of discount	2,918,579			2,692,740
Long-term debt-related parties, net of discount	8,930			349,135
Deferred revenues	29,994			33,500
Other non-current liabilities	2,280			23,162

Commitments and contingencies	—			—

Stockholders' deficit
Preferred stock, $0.0001 par value, 5.0 million shares authorized, none issued	—			—
Common stock, $0.003 par value
Authorized: 240.0 million shares at December 31, 2010 and 2009
Issued and outstanding: 67.8 million and 56.7 million shares at December 31, 2010 and 2009, respectively	204			170
Treasury stock: 1.5 million and 0.7 million shares at December 31, 2010 and 2009, respectively, at cost	(4,338		)	(1,494		)
Additional paid-in-capital	404,125			336,971
Accumulated deficit	(1,061,449		)	(985,246		)
Accumulated other comprehensive income	(173		)	(133		)
Total stockholders' deficit	(661,631		)	(649,732		)
Non-controlling interest	189,021			217,605
Total deficit	(472,610		)	(432,127		)
Total liabilities and deficit	$	2,553,507		$	2,732,622

The accompanying notes are an integral part of these consolidated financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF OPERATIONS

(in thousands, except per share data)


	Year Ended December 31,
	2010			2009			2008
Revenues
LNG terminal revenues	$	269,538		$	170,071		$	—
Marketing and trading	19,022			8,087			2,914
Oil and gas sales	2,858			2,866			4,215
Other	95			102			15
Total revenues	291,513			181,126			7,144

Operating costs and expenses
LNG terminal and pipeline development expense	11,971			223			10,556
LNG terminal and pipeline operating expense	42,415			36,857			14,522
Oil and gas production and exploration costs	627			471			526
Depreciation, depletion and amortization	63,251			54,229			24,346
General and administrative expense	68,626			65,830			122,678
Restructuring charges	—			20			78,704
Total operating costs and expenses	186,890			157,630			251,332

Income (loss) from operations	104,623			23,496			(244,188		)
Gain (loss) on sale of equity method investments	128,330			—			(4,800		)
Gain (loss) on early extinguishment of debt	(50,320		)	45,363			(10,691		)
Derivative gain, net	461			5,277			4,652
Interest expense, net	(262,046		)	(243,295		)	(147,136		)
Interest income	534			1,405			20,337
Other income	24			99			90
Loss before income taxes and non-controlling interest	(78,394		)	(167,655		)	(381,736		)

Income tax provision	—			—			—
Loss before non-controlling interest	(78,394		)	(167,655		)	(381,736		)

Non-controlling interest	2,191			6,165			8,777
Net loss	$	(76,203	)	$	(161,490	)	$	(372,959	)

Net income (loss) per share attributable to common stockholders - basic and diluted	$	(1.37	)	$	(3.13	)	$	(7.87	)
Weighted average number of common shares outstanding - basic and diluted	55,765			51,598			47,365

The accompanying notes are an integral part of these consolidated financial statements.

CHENIERE ENERGY, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF STOCKHOLDERS’ (DEFICIT) EQUITY

(in thousands)

Common Stock

Treasury Stock

Additional Paid-in Capital

Accumulated Deficit

Accumulated Other Comprehensive Loss

Non- controlling Interest

Total

Equity/(Deficit)

Amount

Balance—December 31, 2007

47,731

143